bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Hydraulic Fracturing (March 2014)
Authors: Olson Karen 
Published: February 2015

Technology Focus
At the 2014 SPE Hydraulic Fracturing Technology Conference in February, former Texas A&M Department of Petroleum Engineering head Stephen A. Holditch received a well-deserved lifetime achievement recognition, the Legends of Hydraulic Fracturing Award. Among the reasons he received this award was that he has demonstrated throughout his career a passion for understanding and explaining to his peers and colleagues what happens during hydraulic fracturing. Through his consulting company and as a professor and department head, he passed his passion along to others. He served on many masters and doctoral candidate committees and directed numerous graduate-student research projects. He continued to spread knowledge by authoring more than 100 SPE papers.
With the rising importance of hydraulic fracturing in the development of unconventional plays and deepwater projects, who among you will be a future legend of hydraulic fracturing? Who among you possesses the passion, the drive to really understand fracturing in these horizons and to advance the science and understanding for yourself, your company, the industry, and the world? Who will take the time to document their work?
As I survey the industry, its leadership styles and career paths, I see familiar themes. Recent graduates come into completions, do their mandatory stint, and then move to the next rotation in order to qualify ultimately for a promotion into management. I am not disparaging this, and I believe in the importance of a well-rounded career as well as an understanding of the well/project life cycle.
But, in closing, I will state that I also believe an engineer should develop an expertise in at least one aspect of their work. So, ask yourself two questions: What is my expertise? What do I want to be remembered for? And then, look inward and contemplate, “What will be my legacy?” JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 166332 Characterizing Hydraulic Fracturing With a Tendency-for-Shear- Stimulation Test by Mark McClure, The University of Texas at Austin, et al.
SPE 163824 Development and Use of High-TDS Recycled Produced Water for Crosslinked-Gel-Based Hydraulic Fracturing by R. LeBas, Halliburton, et al.
SPE 166298 Influence of Hydraulic Fractures on Wellbore/Sandface Temperatures During Production by J.F. App, Chevron Energy Technology Company
SPE 166550 Offshore Horizontal-Well Fracturing: Operational Optimization in the Southern North Sea by Marc Langford, Centrica, et al.
Slurrified Heavy-Oil-Reservoir Extraction as a Recovery Method
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165498, ’Slurrified Heavy-Oil-Reservoir Extraction (SHORE): A Nonthermal, In-Situ Recovery Method,’ by David P. Yale and Jianlin Wang, ExxonMobil Upstream Research; Steven W. Meier, Eric Herbolzheimer, and Arnold P. Kushnick, ExxonMobil Research and Engineering; Neal L. Adair and Sergio A. Leonardi, ExxonMobil Upstream Research; and Richard J. Smith, Imperial Oil Resources, prepared for the 2013 SPE Heavy Oil Conference—Canada, Calgary, 11-13 June. The paper has not been peer reviewed.
This paper presents a concept for recovery in Canadian oil sands that uses water injection to condition a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. The ability of the process to work in thinner and more geologically complex reservoirs compared with other in-situ processes, and with lower CO2 and surface footprints than those seen in thermal and mining processes, could make this an attractive alternative recovery process for shallow- to intermediate-depth in-situ bitumen resources.
Introduction
Canadian oil-sands recovery is challenged by the high and ultrahigh viscosity of the heavy oil and bitumen trapped within the generally unconsolidated sand matrix of these reservoirs. Steam processes have dominated the in situ recovery of this resource, but steam/ solvent and solvent-only processes are currently being field tested. Steam processes, especially low-pressure processes such as steam-assisted gravity drainage (SAGD), are challenged by both a high degree of geologic heterogeneity and thin pay zones.
In-Situ Mining of Oil Sands
The very shallow (less than 70-m) depth of a large portion of the oil-sand deposits of Canada has made their surface mining a technically feasible and economical method of recovering the bitumen from the shallowest portion of the oil sands. The success of surface mining for bitumen has led others to propose and test in-situ bitumen mining processes. Hydraulic mining of the oil sands from a borehole has a rich patent literature but few conclusive field tests. The basic concept is that a high-pressure, downhole water jet could disrupt the unconsolidated sand matrix around the wellbore such that a bitumen/water/sand slurry could then be produced to the surface for bitumen extraction with surface-mining techniques. The process is technically challenged by the limited volume of hydrocarbons that can be recovered from any given wellbore and the limited “cavern” size that can be supported without roof collapse in these unconsolidated sand/shale geologic environments.
The Role of Autonomous Flow Control in SAGD Well Design
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166266, ’The Role of Autonomous Flow Control in SAGD Well Design,’ by Sudiptya Banerjee, SPE, Robert Jobling, SPE, Tarik Abdelfattah, SPE, and Hang Nguyen, SPE, Baker Hughes, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
One notable improvement originating from recent field experience is the novel use of injection-/inflow-control devices (ICDs) in a conventional steam-assisted-gravity- drainage (SAGD) well pair. The use of a properly designed ICD completion has proved beneficial to the processes of developing the steam chamber and improving the inflow profile of the producing well of the SAGD pair. Work conducted in the Surmont field of Alberta, Canada, provided an excellent starting point to optimize flow-control improvements to the SAGD process.
Introduction
To obtain high efficiency, the SAGD process demands a high degree of steam conformance along the wellbore. The better the steam conformance, the greater the amount of oil mobilized and the higher the potential for oil recovery. However, conformance should not come at the cost of excessive steam injection.
A number of thermal inefficiencies (described in the complete paper) are unavoidable in the SAGD process. These collectively result in a deformed and nonoptimal steam chamber that undermines energy maintenance and lowers the ultimate recovery factor. By incorporation of flow-control devices (FCDs) into the injector or producer well, however, a more ideal, more desirable chamber shape can be realized.
Overview of ICD Geometries
Fundamentally, all flow-control devices operate by the same mechanism: They provide an additional pressure drop at select points in the completion string to complement the pressure drop of fluid moving through the reservoir as well as internal pressure drops within the completion itself. Despite this fundamental similarity, however, the methods by which different styles of ICDs create this pressure drop vary strongly with design.
There are three distinctive categories of passive inflow-/injection-control devices (PICDs) available today. The two most common PICD geometries are orifice/tube/nozzle-based (restrictive) (Fig. 1) and helical-channel/baffled- pathway (frictional) (Fig. 2). The restriction-based PICD uses fluid constriction to generate a differential pressure across the device. This method essentially forces the fluid from a larger area through small-diameter ports, creating flow resistance. A frictional-pathway PICD relies instead on surface friction to generate a similar pressure drop. These designs produce a distributed pressure drop over a relatively long area, as opposed to the instantaneous loss through a restriction-style PICD. When fluid flows through the channel/ channels, fluid rheology and channel characteristics interact to create the designed pressure drop.
Instantaneous 4D Seismic Used to Monitor Offshore Water-Injector Wells
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16901, ’Instantaneous 4D (i4D) Seismic: An Innovative Concept To Monitor Offshore Water-Injector Wells,’ by J.G.F. Stammeijer, M. Davidson, P.J. Hatchell, and J.L. Lopez, Shell, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission.
In this paper, the authors propose a new method for time-lapse-seismic surveys focused on water-injector wells. The “instantaneous 4D” (i4D) method aims to acquire dedicated high-quality 4D data with a short turnaround time at cost levels low enough to make it affordable to repeat such data-acquisition programs reasonably frequently. We have implemented the method as a variation on surveys that use ocean-bottom seismometers. We suspect that our method can also be combined with other means of seismic-data acquisition (for example, permanent reservoir-monitoring systems and vertical-seismic-profiling systems in wells).
Introduction
Time-lapse, or 4D, seismic is frequently used offshore to monitor fluid-movement processes such as waterflood or aquifer drive. These processes happen at relatively slow time scales (years). As a result, proper monitoring of these effects requires repeat surveys to be acquired every 3 to 5 years or so.
Recent examples in industry show that fast reservoir changes (months) also are taking place. The observed changes are often associated with water-injector wells. For example, one water-injection well documented in the literature produced large time-lapse signals in less than 1 year after its startup. Because of cost and other considerations, it is not feasible to repeat fieldwide 4D surveys often, nor to install permanent monitoring systems in many of those fields. Yet there is a need to monitor such phenomena more frequently and with short reaction times. This is where the authors believe that the i4D method can play an important role.
This method is not intended to replace full-field surveys. Rather, it adds small surveys more frequently in between regular full-field surveys to enable better observation of fast 4D reservoir effects along with slow changes. It can be seen as filling the gap between the current practice of infrequent full-field surveys and the installation of permanent reservoir-monitoring systems, which can be expensive.
Comments: Looking Ahead (April 2010)
Authors: Donnelly John 
Published: February 2015

Editor's column
Every year, IHS/Cambridge Energy Research Associates brings together some of the world’s top energy executives to Houston for a weeklong conference. The event acts as sort of a state-of-the-industry temperature check and spawns discussion about where the industry is now and where it is heading. Last year’s theme was surviving financial turbulence; this year’s reflected the sense of recovery both in the industry and world economies.
Amid the panel sessions and more focused breakout sessions, a general consensus arose about what may lie ahead for the oil and gas industry in the near future.
The recent highly publicized shale gas plays in the US have the potential to be one of the most significant developments in decades, and could decidedly change the industry—including markets and trade, investment, and supply/demand fundamentals. But this is not just a North American phenomenon—there is huge potential for unconventional-gas development in other parts of the world.
Thanks to the breakthroughs in shale production and global liquefied natural gas projects, gas can no longer be thought of as just a “bridge” fuel to future alternative energy.
Despite all of the talk of alternative energy sources the past few years, hydrocarbons will still be the major source of energy supply for at least the next 20 years and likely much longer.
Globalization of supply has existed for years, as producers around the world focused on key demand centers such as the US, western Europe, and Japan. But demand in these regions is peaking and the world is now witnessing a globalization of demand.
And the world will need all energy resources—hydrocarbons, nuclear, solar, wind, etc. to meet future world energy demand. There is no going back in the developing world as it moves toward a more energy-rich, more affluent, and more efficient economy and lifestyle.
Although global warming has lost policy momentum this year after the Copenhagen conference and controversy surrounding how some data were arrived at, the industry will continue to confront legislative and public concern over “climate change.” The march toward a lower-carbon future will continue, although many may not be aware of how difficult and expensive that transition will likely be.
The key to increasing supplies to meet growing demand lies in technology. The oil and gas industry certainly appears to be entering an era of transition. Oil supply growth appears to becoming more concentrated with only about a dozen or so regions with potential to grow, including Russia, Africa, Eurasia, and the Middle East. Demand growth has decidedly shifted to developing economies. And oil is now intertwined more than ever with financial and commodity markets as well as the climate debate, which will lead to not only the need for more transparency in the future but more regulation.
Techbits: Malaysia Workshop Highlights Production Enhancement
Authors: JPT staff _ 
Published: February 2015

Techbits
SPE highlighted the importance of maximizing production during economic downturns at the Applied Technology Workshop “Production Enhancement—Maximizing Production and Recovery in a Challenging Economic Climate.” The workshop, held in Penang, Malaysia in October 2009, brought together an international group of 91 participants to discuss and challenge the use of production-enhancement technologies.
The first keynote address by Ramlan Malek, vice president, E&P, Petronas discussed the importance of production-enhancement technologies such as improved-oil-recovery and enhanced-oil-recovery strategies in improving Malaysia’s recovery factor from the current 34–35% to more than 40%. His talk also addressed effective marginal-field development to increase and prolong peak production in Malaysia.
A second keynote address by Golden Energy Chief Executive Officer Mark Pearson discussed the role of engineers and practitioners in evaluating, applying, and benchmarking production-enhancement technologies. He also provided a historical perspective of the growth of hydraulic-fracturing technologies in the US for developing its abundant tight gas plays. He believes there is a revolution in hydraulic technologies led by multizone, staged fracturing; slickwater fracturing; and horizontal-well fracturing. These—together with the integration of microseismic mapping, reservoir visualization, and fracture-design models—are enabling technologies in the US unconventional-reservoir hydrocarbon development.
Assessing Business Value Petronas’ Supply Chain Manager En. Suhaimi Yasin opened the first technical session with a discussion on strategies to address the new reality of lower hydrocarbon prices without a commensurate drop in costs for rigs and services. This market dynamic has caused Petronas to re-evaluate strategies to manage cost and value. Initiatives being adopted include strategic alliances on a risk/reward basis, longer-term contracts on a partner-ship basis, e-procurement, and better leveraging of technology.
Oddbjorn Skilbrei of Shell EPA discussed Lean Management Principles employed in Shell Malaysia assets to achieve breakthrough performance. The use of Lean Management Techniques has resulted in improved recognition of event triggers in well performance and reduced cycle time to fix the events. The group discussion emphasized the importance of accurate data gathering and team communication.
Feroney Serbini of Schlumberger closed the session with a case study on integrating surface network modeling with a reservoir model. The study benchmarked proposed solutions against the unconstrained model, and the selected solution provided a production increase of 1 million bbl more than the second best solution. The ensuing discussion focused on gaining further insight on the modeling methodology.
The First FPSO in the US Gulf of Mexico: The 14-Year Journey
Authors: Lovie Peter 
Published: February 2015

Editor’s note: This is the first of two articles on the technical challenges and regulatory hurdles that were overcome to allow the use of floating production, storage, and offloading vessels (FPSOs) in the US Gulf of Mexico (GOM). The FPSO that will be installed at Petrobras’ Cascade-Chinook development in the deepwater GOM is planned for mid-2010 startup.
The practical start of the journey of the first floating production, storage, and offloading (FPSO) vessel to the US Gulf of Mexico (GOM) came in 1996, when an operator thought that an FPSO might be a viable candidate to efficiently develop a deepwater prospect. Back then there were a number of FPSOs in operation in different parts of the world, so the idea was not revolutionary. Several conference papers at the time showed potential arrangements for an FPSO at Texaco’s Fuji development. As events unfolded, estimates of reserves were not as good as initially expected and the Fuji prospect was abandoned, but the idea of considering an FPSO in the GOM had taken hold.
During 1998–1999, Shell and its partner BP conducted feasibility studies for using an FPSO at its Na Kika development, involving study work by leading FPSO contractors. These studies were not just simple paper exercises, although traditional paper studies were made. Groups of facilities and subsurface experts met, examining every aspect of proposed candidates for field development and debating the pros and cons of solutions. Many in the industry may not appreciate the rigor of these debates unless you were in the middle of them. And in the middle of all this was a patient, objective participant, bringing out the best in everyone, George Rodenbusch of Shell (see sidebar).
Despite every consideration given to the FPSO option, all these debates and studies led to the conclusion that for the particular field at hand an FPSO was not the best solution, and today a semisubmersible is the centerpiece of the Na Kika development.
Again in 2000–2001 a supermajor looked exhaustively at the FPSO option but, weighing the regulatory uncertainties at the time and competitive pipeline economics, the FPSO and shuttle-tanker combination lost out to spars and semisubmersibles. About this time another development for another operator prompted presentations at an SPE lunch meeting in Houston showing shuttle tankers and an FPSO as the way to go. But that development became a tension leg platform (TLP), exporting via pipeline to produce that asset.
During this period some operators—often from outside the US—concluded that there was prejudice in the US against FPSOs, but the evidence of these repeated considerations of FPSOs over the years does not bear this out. Regulatory expert Rick Meyer of Shell summed it up in a presentation at an SPE workshop in 2002: “Economics, economics, economics.” It was more a matter of just not having the right project for an FPSO in the GOM.
Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124324, ’Drilling and Evaluation Technologies Extend Operating Limits in Challenging High-Pressure Deepwater Environments,’ by Waitus Denham, SPE, Shell, and Brian Donadieu, SPE, Ernest Lee, SPE, Rohit Mathur, SPE, and Ananth Srinivasan, Baker Hughes, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.
New drilling opportunities require technological innovations to increase efficiencies and optimize production. Some newer drilling operations, particularly in deep water, involve extreme environments such as ultrahigh pressures that require new approaches. With downhole pressures approaching 30,000 psi and escalating rig costs, rotary-steerable systems (RSSs) and advanced formation-evaluation technologies are needed.
Introduction
Advances in rig design, in downhole tools, in data communications, and in other areas result from challenges associated with pushing and extending limits. While in the planning stages of a deep-water high-pressure well, risk mitigation and contingency planning are critical in making technology advances. It is important to balance the drive to advance technology with the value created.
Solution Potential
In many cases, wellbore construction can be accomplished with standard off-the-shelf products and services. When the location moves into deep water, the complexity, risks, and costs of those operations require fit-for-purpose or application-based solutions.
In this case, early in the design phase of the well, increased potential of a high-pressure situation was evident that would require equipment that was unavailable at the time. Therefore, the operator approached a selected vendor and began a feasibility study. Open communication between the companies was critical. After developing an understanding of the operator’s critical success factors, the service company gained clearer insight into the challenges at hand and was able to address the effects and risks associated with “new” technology.
Development Stage
Typically, well-construction planning involves a few key individuals from both companies. For this case, it was important to involve additional sup-port and expertise to ensure success. Expanded teams from the operator included the drilling, geology, and petrophysical disciplines, along with asset-management and offshore-operations experts. The vendor expanded its operations, applications-engineering, and technical-support functions to include reliability engineering, product development, quality management, repair, and maintenance.