bluuebunny/crossref_metadata_2025_split huggingface dataset:
Worldwide Deepwater Petroleum Exploration and Development Prospectivity: Comparative Analysis of Efforts and Outcomes
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125085, ’Worldwide Deepwater Petroleum Exploration and Development Prospectivity: Comparative Analysis of Efforts and Outcomes,’ by Omowumi O. Iledare, SPE, Louisiana State University, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.
Empirical indicators derived from deepwater-specific data show that the expansion in deepwater operations is a response to global oil demand as onshore petroleum resources deplete. A study showed that the evolution of deepwater development is very pronounced around the three Atlantic basin deepwater zones (Africa, Latin America, and North American Gulf of Mexico).
Introduction
The empirical indicators were derived from deepwater-specific data obtained from private and public sources, including an online private database purchased from Infield Oil Field Systems, information collected over time at the Center for Energy Studies, and public data from the US Department of the Interior online database of the Minerals Management Service. Here, deepwater operations are defined as Slope, water-depth range between 200 and 400 m; Deep, water-depth range of 400 to 1500 m; and Ultradeep, water depth greater than 1500 m. Operating firms are classified as an international oil company (IOC), a national oil company (NOC), or a local/independent oil company (LOC). Worldwide, deepwater petroleum basins were classified into five regions—Africa, Latin America, North America, Europe, and other (Asia, Australasia, Middle East, and the Caspian). The study period was 1983–2007.
Factors Affecting Deepwater Operations
Petroleum pricing encourages companies to search for and develop petroleum resources, including the more difficult areas such as the deep offshore. Technology progress in geological-information gathering and processing has made exploration and production operations more efficient. Advances in exploration, drilling, completion, and production technologies have made the search for and development of petroleum more cost effective and environmentally responsible. Frontier areas considered uneconomical and too difficult a few decades ago have become prime targets for petroleum exploration and development as a result of improved imaging technologies, including 3D-seismic and time-lapse systems.
Open access to petroleum resources in deep water is wider in the three Atlantic basin deepwater zones—Africa, Latin America, and the Gulf of Mexico. Currently, most deepwater operations and activity are concentrated in Africa, Latin America, and the US Gulf of Mexico.
Global Appraisal
Attributes of worldwide deepwater prospectivity include fields discovered, fields on stream, discovery-to-production lag, field-depletion life, operational wells, wells under development, and future wells. Well completions have either subsea or surface wellheads.
Technology Focus: EOR Operations (June 2010)
Authors: Bonet-Cunha Luciane 
Published: February 2015

Technology Focus
The world has not changed much the past 4 to 5 years. However, we do know a couple of things that have changed. One that affects the energy industry and our daily lives is the price of oil, which has gone up and stayed up. This fact, together with the decrease in the number of new discoveries and the ever-increasing number of maturing fields worldwide, has augmented attention in the enhanced-oil-recovery (EOR) area. There is a huge target out there in the form of residual hydrocarbons. The oil industry’s common goal is to move these resources to reserves and do it safely in an environmentally responsible, reliable, and cost-effective way. EOR technologies are vital in achieving this goal. As a result, many recently planned EOR projects are being implemented and others will be implemented in the coming years.
However, despite many developments and successful implementations, EOR is still a risky business, low on the learning curve and in reliability. Important success factors for an EOR project are a robust characterization of the reservoir, use of reliable reservoir-surveillance technologies, and implementation of efficient operations with minimized operational costs.
To be successful when applying an EOR process, it is critical to address the proxy of ongoing operations and to achieve more-efficient operations workflows. These workflows require a triangular collaboration between oil companies, suppliers, and R&D institutes working together to find creative solutions to produce the oil and gas and to develop new technologies. The papers selected for this feature illustrate a few examples of the latest accomplishments of suppliers of new technologies, along with customers who are applying them. I hope you will find them of interest.
EOR Operations additional reading available at OnePetro: www.onepetro.org
SPE 124614 • “Determining Reservoir Properties and Flood Performance From Tracer-Test Analysis” by G. Michael Shook, SPE, Chevron, et al.
SPE 122018 • “Overcoming Poroelastic Behavior in the Water-Injector Wells in the Kikeh Deepwater Development” by Tamara Webb, SPE, Murphy Oil, et al.
IPTC 13346 • “Staged Design of an EOR Pilot” by B.L. Adibhatla, SPE, ExxonMobil, et al.
Case History: Steam-Injection Monitoring With Optical-Fiber Distributed-Temperature Sensing
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127937, ’Case History - Steam-Injection Monitoring with Optical-Fiber Distributed Temperature Sensing,’ by Marcelo A.P. Batocchio, SPE, Halliburton, and Adriana L.C. Triques, Hardy L.C. Pereira Pinto, Luis A.S. de Lima, Carlos F.S. Souza, and Ronaldo G. Izetti, Petrobras, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March.
A project was initiated by Petrobras to map the steam-front progress in a steam-assisted-production heavy-oil field. A distributed-temperature-sensing (DTS) system was installed to monitor the temperature distribution in a wellbore of a pilot program having three producers and one continuous-steam-injection well.
Introduction
In heavy-oil fields produced by steam injection, companies seek information to improve the drive mechanism that moves the crude oil into the wellbore. Monitoring equipment and interpretive-software tools help to achieve production requirements, maintain economic feasibility, and promote safety. In this project, high-temperature conditions were factors also.
Optical-fiber DTS is a downhole-monitoring technology that provides permanent and continuous well-temperature profiling. This method enables real-time data collection, whereas traditional downhole monitoring during production provides temperature data only at a fixed point for each reading. Alternatively, wireline temperature logs can be run, but this method does not offer continuous monitoring and it affects production. With the DTS technique, the optical fiber typically is attached to the tubing and provides a complete log of the well temperature for each reading, enabling permanent and continuous monitoring without production interruption. Steam-front progress, which can improve the understanding of the reservoir geological model, can be followed; steam-breakthrough can be identified; and improved injection-efficiency then can be achieved.
Project Implementation
Estreito is an onshore field in northeast Brazil, 180 km from the city of Natal. This field is part of the Potiguar basin. The main reservoirs are Açu 100 and Açu 50/60, which are part of the Açu formation. These shallow reservoirs (approximately 200 m deep) originated from a fluvial depositional system. They have strong heterogeneities, have a strong active bottom aquifer (Açu 100), and are controlled by an ensemble of faults known as Carnaubais. The 15°API oil has high viscosity (2,000 cp).
Cyclic steam injection began in 1984 as an improved-recovery process. This method is no longer economically viable and is being replaced by continuous steam injection.
The efficiency of continuous steam injection is related directly to knowledge of heat-flow paths, which is reflected in the steam/oil ratio and the recovery factor of the area. Therefore, the operator has monitored heat transfer throughout the field since the beginning of steam injection.
Combining Distributed-Temperature Sensing With Inflow-Control Devices for Improved Injection Profile
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127772, ’Combining Distributed-Temperature Sensing With Inflow-Control Devices Provides Improved Injection Profile With Real-Time Measurement in Power-Water Injector Wells,’ by Drew Hembling, and Garo Berberian, SPE, Saudi Aramco, and Mark Watson, Sam Simonian, and Garth Naldrett, SPE, Tendeka, prepared for the 2010 SPE Intelligent Energy Conference, Utrecht, The Netherlands, 23-25 March.
Passive inflow-control devices (ICDs) are used to enhance the performance of horizontal producing wells in unfavorable environments such as nonuniform permeability and/or pressure variations along horizontal sections. ICDs were combined with a fiber-optic distributed-temperature-sensing (DTS) system to manage the water-injection profile across a reservoir horizon. This field trial demonstrated the effectiveness of the ICD system when used for injection-well profiling and for fluid diversion during acid stimulation.
Introduction
To understand the injection profile and well performance, a DTS system was deployed with ICDs and swellable packers as a field trial in a planned injection well. The objectives were to provide real-time information on multirate testing, determine real-time compartmental-injection profiling, and eliminate the need for horizontal flowmeter logging and well intervention.
Recent designs use ICD-completion technology with a DTS umbilical deployed in the openhole producing section below a liner for real-time monitoring and controlling of inflow from each compartment, thereby extending well life and increasing recovery. This case involved the use of DTS and ICD technology to control injection profiles in an openhole near-horizontal well. Compartments were created by use of water-swellable packers with feedthrough capabilities for the DTS umbilical.
Completion Design
The reservoir section was separated into six compartments. On the basis of openhole-log analysis, the reservoir has a uniform porosity along the length of the well, with a few dolomite intervals present. The spacing of the ICDs and packers was planned in such a way as to isolate these dolomite sections while distributing the desired injection rate along the well. To mitigate the risk of getting stuck while running the lower completion to total depth, it was decided to limit the number of openhole packers to six, thereby reducing the number of allowable compartments.
DTS System and Installation
The DTS and a permanent downhole-monitoring system were installed in April 2009. The fiber-optic DTS cable was attached and secured to the production-tubing string and provides multipoint temperature profiles across the length of the well. The real-time data from the DTS system can be used for injection optimization and reservoir management by monitoring injection rates between and within the ICD compartments and by identifying crossflow conditions.
Shale Holds Huge Potential for Researchers at Universities
Authors: Rassenfoss Stephen 
Published: February 2015

A simple question, “Can you tell us about shale?” has spawned growing research programs at universities around the globe.
In less than five years, industry-supported university research has played a key role in defining the structure and elements in shale. The work in a group of laboratories at the University of Oklahoma (OU) in Norman, Oklahoma, is an example of the competitive drive to understand these challenging rocks.
Now the goal is to explain the inner workings of these rocks and use that understanding to find more oil and gas and produce it far more efficiently.
“The whole thing started with the question: Can you tell us about shale? It is leading into so many interesting areas,” said Chandra Rai, who along with Carl Sondergeld has led the OU lab at the Mewbourne School of Petroleum and Geological Engineering. The pair and a longtime lab manager moved into academia in 1999 when BP donated its petrophysics lab to the university.
At the time, shale exploration was often still seen as little more than an interesting experiment by Mitchell Energy Company in the Barnett Shale around Fort Worth, Texas. During the following decade:
The lab—renamed the Integrated Core Characterization Center—moved to OU’s main campus in Norman.
Devon Energy bought Mitchell Energy and showed that drilling horizontal wells could significantly increase shale gas production.
The industry mobilized to tap the enormous potential in unconventional reservoirs.
In 2004, Devon’s shale exploration team started seeking more outside advice.
“When we began to look at it, we realized we had some big questions about shale,” said Jeff Hall, vice president of exploration at Devon. On the list were: How does oil and gas move through the rocks to the wellbore? How can we better complete wells in this reservoir? There are big differences in production from well to well. Why is that?
Devon’s shale research led it down a meandering path. It started with a geophysical study that morphed into a geological study that raised engineering questions. Hall said, “We began to realize it is more complicated.”
To begin with, researchers had to find tools capable of looking into the structure of these extremely fine-grained mudstones. When they did, it was clear the name shale covered a variety of things. “People started with the idea that all shales were all the same,” Sondergeld said. “It is amazing when you see the microstructure how different they are.”
Other companies and universities followed a similar path into shale research. The size of the resource, and the work needed to go after it, are both huge. From the start, the research indicated how unconventional shale reservoirs really are. As the list of questions grew, so did the range of experts involved.
Technical Talent Shortage Could Begin to Limit Growth
Authors: Rousset Jean-Marie , Bismuth Pierre , Soupa Olivier 
Published: February 2015

Talent & Technology
How do you transition an industry from conservative and slow moving in terms of human resources (HR) strategy to proactive, responsive, and ready to take risk? This is the quandary facing exploration and production (E&P) companies at a time when a “big crew change” is under way. The industry will see a serious shortfall of experienced technical professionals from attrition in the coming five years when the call on technical expertise will be greater. An increasingly stringent post-Macondo regulatory environment and new frontier and unconventional oil and gas plays will leave companies struggling to maintain current operations and drive growth.
Schlumberger Business Consulting’s (SBC) annual Oil & Gas HR Benchmark survey provides information on trends involving petrotechnical professionals, namely geoscientists and petroleum engineers. Compiled from the responses of oil and gas companies and universities, the study has become a reference point for E&P executives seeking to understand industry trends and develop HR strategies that provide a competitive edge and sustainable business performance. The survey highlights best practices and gives insights into an often misunderstood and underestimated element of the global oil and gas industry: talent requirement.
The 2010 survey shed light on two important facts for the industry’s supply chain of talent: the demographic transition or “big crew change” is now taking place, and technical talent has become a true strategic enabler for delivering production and future growth.
Demographic Transition
More than 25% of petrotechnicals currently working for E&P companies are older than 50 years of age and the vast majority will retire in the next five years. This is the generation of professionals who joined the industry during the late 1970s and early 1980s at the peak of the oil and gas expansion cycle. The crisis of 1986 marked the brutal end of that expansion and the beginning of a long period of anemic recruitment that lasted nearly two decades and created an irreversible void in the ranks of today’s midcareer professionals. The vigorous upcycle of 2003 to 2008 has provoked a rapid and important uptick in graduate recruitment (a three-fold increase). This has finished shaping the sector’s demographic profile with its recognizable double-hump of young and senior petrotechnicals surrounding a gap of midcareer professionals (Fig. 1).
Coiled Tubing Operations From a Work Boat
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 141234, ’Coiled Tubing Operations From a Work Boat,’ by N. Long, SPE, Brunei Shell Petroleum, and R. Raj, S. Srisa-ard, SPE, and N.H. Son, SPE, Schlumberger, originally prepared for the 2011 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 5-6 April. The paper has not been peer reviewed.
Small offshore platforms have low deck-load capacity, and available deck space is insufficient for coiled-tubing (CT) workover operations. To find a solution to this issue, CT operations from a vessel were discussed and subsequently developed more than a decade ago. In 2002, the technique was refined substantially to improve safety and reliability, which allows well intervention from the deck of a floating anchored vessel. This technique uses a system that provides emergency CT disconnect and effectively compensates wave motion.
Introduction
As with any mature oil and gas fields, maintaining and improving oil and gas production is considered part of production operations. Each year, Brunei Shell Petroleum typically selects a minimum of more than 60 wells as candidates for CT intervention. These candidates usually are distributed over 30 different offshore platforms. In terms of operational time, this intervention objective normally requires continuous activity for 7 to 8 months.
When studying the feasibility of conventional CT well intervention on a small production platform, there are normally three main issues to be examined. First, the platform deck area for placing equipment should be sufficiently large for placing CT equipment, pumping equipment, wireline equipment, and testing equipment, and for allowing equipment access spaces. Second, the platform crane must be able to lift equipment dynamically from a supply boat to the platform. Third, the production-platform structure must be strong enough to withstand the total weight of the CT equipment.
In Brunei, normally it is not feasible to place all the CT equipment on offshore production platforms because the decks of those platforms are too small. CT-intervention-work targets on three-leg platforms and four-leg platforms that have available deck space range between 214 and 1,905 ft2. The maximum deck loads corresponding to these areas are in the range of 19 to 173 t. The installed crane on these platforms is primarily for lifting small loads, which are needed to support production operations. Therefore, the dynamic crane capacity is usually less than 5 t, and its boom length is approximately 15 ft.
CT well-intervention work commonly includes wellbore cleanout, wellbore mechanical-obstruction retrieval, sand control, adding perforations, and matrix acidizing. To cover all these types of work, the deck-space requirement for setting up equipment should be at least 3,500 to 4,000 ft2 (or more) and deck-load capacity should be between 170 and 270 t.
Radio Frequencies as an Oil-Production Stimulation Method
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133085, ’Quantum Effects Imparted by Radio Frequencies as a Stimulation Method of Oil Production - Part II,’ by J. Mike Brown, SPE, Harold L. Becker, and Greg Darby, SPE, BJ Services, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
Tuned energy waves alter molecular bonds in the well-tubular and near-wellbore regions to stimulate production by disrupting damaging deposits and altering relative permeability. New studies elucidate the action mechanism and the range of the application.
Introduction
The full-length paper is a continuation of paper SPE 124144 in which a method of stimulating producing wells by use of electromagnetic frequencies was described. The frequencies used by the device are in the range used in nuclear-magnetic- and electron-spin-resonance spectroscopy. The mode of action is thought to be the result of changing the nuclear- and electron-spin states of molecules such as paraffin waxes and altering the degree of hydrogen bonding and charge induction that allow aggregation and networking of the wax particles.
A recent study of the process provided additional insight to explain the action mechanism and to aid candidate selection. Laboratory core-flow studies showed that wettability reversal can increase production by removal of production impairments. Not all treated wells have shown measureable increases in production, and additional work is needed to improve candidate selection. Some wells that did not show a production increase benefited in reduction or elimination of workover and conventional chemical treatments. The electromagnetic frequencies used in this iteration of the device target near-wellbore damage resulting from wettability changes caused by hydrocarbon-based deposition or past production practices that resulted in this type of damage. These frequencies are in the radio-frequency (RF) band of electromagnetic radiation.
Relative Permeability Modification
Core-flow studies on native oil-wet sandstone were conducted to evaluate the effect of RF treatment on the relative permeability of oil and water. During core preparation, differential pressure and flow rate were monitored to calculate effective permeability to oil at irreducible water saturation (KoSwi). The sample was unloaded from the core holder and transported to a laboratory RF unit for treatment. Following a 15-minute RF-treatment period, the sample was reloaded into the core holder at 180°F. Alternating cycles of mineral oil, 2% KCl, and then mineral oil again were injected. Differential pressure and flow rate were recorded and the permeability was calculated. The sample was unloaded from the core holder and subjected to a second 15-minute treatment. The sample was reloaded into the core holder at 180°F and alternating cycles of mineral oil and 2% KCl were injected. Differential pressure and flow rate were recorded, and the permeability was calculated.