bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Fracturing: Internal Breakers for Viscoelastic-Surfactant Fracturing Fluids
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 106216, "Internal Breakers for Viscoelastic-Surfactant Fracturing Fluids," by James B. Crews, SPE, and Tianping Huang, SPE, Baker Oil Tools, prepared for the 2007 SPE International Symposium on Oilfield Chemistry, Houston, 28 February-2 March. The paper has not been peer reviewed.
Over the past 2 decades, viscoelastic-surfactant (VES) fluids used for gravel packing, frac packing, and conventional hydraulic fracturing have relied primarily on external or reservoir conditions to break the fluid's viscosity. Internal-breaker technology has been developed that allows breaking VES fluids into easily producible fluids without the need for contacting reservoir hydrocarbons. Very little pressure or time is required to break the fluid when an internal breaker is present.

Introduction
During the 1980s, a VES fluid was developed for gravel packs. Also introduced was the concept that no internal breaker was required. This concept was also applied to VES fluids developed for frac packing and conventional hydraulic fracturing during the 1990s. The stated reason for not requiring an internal breaker was that the VES micelles, which impart fluid viscosity, are sensitive to and will break upon contacting reservoir hydrocarbons, including gas hydrocarbons such as methane, ethane, and propane. During production, reservoir hydrocarbons are said to come into contact with the VES fluid in the pores of the reservoir and, thereby, will readily break the VES-fluid viscosity and allow the once-viscous fluid to be removed easily. It should be noted that a viable internal-type breaker technology has not existed for VES fluids until recently. With the introduction of internal VES-breaker technology has come the ability to evaluate the need for such technology. The full-length paper details laboratory data for evaluating the cleanup of VES fluids with and without internal breaker. The data show internal breakers may improve VES-fluid cleanup without the need for relying on an external breaking mechanism and show how VES fluids without internal breaker may be difficult to move and clean up under certain conditions.

Internal Breakers
In a broad sense, internal breakers are compounds placed within the VES fluid during surface mixing that will go wherever the fluid goes, ensure the VES fluid breaks, and break the VES fluid into an easily producible fluid. The use of internal breakers also should improve the rate and ease of VES-fluid cleanup and prevent viscous emulsions from forming when problematic reservoir hydrocarbons contact, mix with, and break VES-laden fluid in the reservoir.
Permeability Updating of the Simulation Model by Use of 4D-Seismic Data
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125632, ’Permeability Updating of the Simulation Model Using 4D-Seismic Data,’ by R. Villegas, University of Leeds, and C. MacBeth and M. Paydayesh, Heriot-Watt University, prepared for the 2009 SPE/EAGE Reservoir Characterization and Simulation Conference, Abu Dhabi, UAE, 19-21 October.
A method is presented for updating a reservoir-simulation model by incorporating permeability that is derived directly from time-lapse-seismic data. The proposed method builds new permeability distributions by integrating a previous 3D-simulation model with 2D-permeability maps from the time-lapse-seismic results. These updates provide an alternative to use of a conventional gradient-based history-matching tool by itself. The largely uncertain petroelastic model can be avoided when history matching to the time-lapse-seismic data.
Introduction
New high-resolution 4D-seismic-acquis-ition techniques have led to many advances, especially in static-reservoir-property estimation. A common reservoir-engineering-context question is to what extent can time-lapse seismic be used to refine the flow-simulation model. Although time-lapse seismic is used to solve challenges such as pressure-/saturation-change separation, researchers have been less successful in estimating reservoir properties such as permeability. Permeability is a reservoir property that has a first-order effect on simulation-model predictions and is important for optimizing the simulation-model predictions. Recent research has focused on developing a history-matching process or seismic-history-matching process to estimate permeability iteratively by use of an objective function matched exactly to the seismic data. There has been little investigation of direct transform of time-lapse-seismic attributes into average-permeability maps of the reservoir. Direct estimation of reservoir properties from 4D seismic, by transformation procedures similar to those used to estimate properties such as porosity and net-to-gross ratio, could be a viable approach. However, a major drawback of all approaches is that permeability is defined as a 2D map rather than a 3D volume. Current work addresses this challenge by designing a scheme to effectively integrate the depth-averaged mapped estimates from seismic to update the 3D-permeability field in the simulation model.
Gaining Competitive Advantage - Aligning Enterprise Architecture with Business Value
Authors: Habib Zahid , Zaheer Ashar , Ashish Ashutosh 
Published: February 2015

Management
Senior management in the energy industry face a number of complex issues that can make for difficult days and restless nights. From volatile commodity prices and skyrocketing E&P costs to increased nationalism, more regulatory compliance and global recessions, there is no shortage of challenges in the energy industry.
During poor market environments, some companies adopt an extremely conservative outlook that includes sharp reductions in capital outlays, across-the-board budget cuts, and significant cost reductions. While these moves may be necessary to weather short-term conditions, they have limited long-term value and, in fact, can hamper effectiveness down the road. Energy executives seeking a more flexible, competitive organization should start at the company’s foundation—enterprise-wide processes and the supporting systems. Robust processes and proper alignment of the systems support governance, reduce complexity, eliminate redundancy, and generate sustainable cost reductions—while providing employees with the proper tools and data.
These business-facing processes and systems are built on and supported by the enterprise architecture. While companies typically focus on enterprise architecture from a back-office perspective, enterprise architecture should be viewed as enterprise-wide, all encompassing, front- and back-office foundational element. Oil and gas companies should take a hard look at their investments starting with a thorough assessment of their enterprise process, systems, and architecture.
Improve Alignment, Utilization
The accounting software used in the Houston office works. The accounting software used in the Brazil office works. But do the two programs work together? And if they do not, how much time and money does your company spend reconciling accounts?
These are the types of problems that are endemic in the energy business: legacy software programs that do not “talk” to one another, cobbled-together information technology (IT) systems from multiple acquisitions, and even separate IT groups, one supporting E&P and the other for the rest of the organization.
It is not uncommon for a field office to report that certain targets are being met—such as operational expenses, variances within range, production totals, etc.—only to find that headquarters has different sets of data and hence different results. These types of disconnects are costly both in terms of actual dollars and also in terms of productivity, efficiency, and employee satisfaction and requires significant manual consolidation, checking, and rechecking.
Spectrum: Myths and Realities About Hydraulic Fracturing
Authors: Thakur Ganesh 
Published: February 2015

President's column
These days it is hard to open a technical magazine or news-paper without reading something on the topic of hydraulic fracturing, especially in the US.
Hydraulic fracturing—variously “fracing” or “fracking” nowadays (the controversy rages)—has been used by the industry for more than 60 years. Although the technique was seen worldwide, the first 30 years were primarily focused on North America but the last 30 years have seen a proliferation in its application to many new reservoir types as a means to maximize resource value. It is now seen in high-permeability oil fields in Alaska, the North Sea, and Russia; unconsolidated formations in the Gulf of Mexico and Santos Basin; and unconventional resources such as shale and coalbed methane developments.
Advances in horizontal drilling and hydraulic fracturing technology have transformed the natural gas supply in North America. With the advent of technology and know-how, the US is primed to become a gas exporter. According to a recent article in The Economist, the gas potential in Europe is similar, with an estimated “639 Tcf of technically recoverable shale gas compare to 862 Tcf in America.”1 But the regulations in Europe are more stern, the environments more geologically challenging, and reserves come at a higher cost of extraction.
Even with years of successful application and the huge potential for reserves, there are a lot of misconceptions about and opposition to the process. Unfortunately, until very recently, little has been done to educate the public and governments.
What role can SPE play in this issue? Simply, through education and the dissemination of transparent factual information. With our membership at more than 104,000 members in 123 countries, we are well positioned to help clear up the myths and shine light on the realities of this important issue. SPE facilitates best practice sharing through conferences, Applied Technology Workshops, Technical Information Groups, and publication of technical journals. In the spirit of enhancing collaboration, SPE takes a step further and exerts a special effort to hold conferences jointly with the other industry professional societies.
In 2011, SPE held its first SPE Technical Summit, which addressed the topic “Hydraulic Fracturing: Ensuring Ground Water Protection,” and resulted in a white paper based on the discussions.2 And as I write this column, SPE is hosting its fourth Hydraulic Fracturing Technology Conference in The Woodlands, Texas. The program committee chairperson, Dan Hill with Texas A&M University, commented on the importance of the conference: “As the enabling technology for the development of vast unconventional resources, hydraulic fracturing continues to increase in prominence in petroleum engineering, making this conference a critically important event for our industry. SPE plays a vital role in facilitating the right people, place, and atmosphere to discuss and document best practices for the industry.”
Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146489, ’Field Application of Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply in Horn River, Canada,’ by Geoffrey C.J. Coppola, SPE, and Ryan C. Chachula, SPE, Encana Corporation, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
One challenge of the Horn River shale play in British Columbia, Canada, has been the increasing number of fracture stimulations required per horizontal wellbore. Critically important is the massive volume of water required to supply the continuous fracturing operations in the development. To eliminate reliance on surface water, it was decided to produce high volumes of sour water from a relatively unknown underpressurized saline aquifer. The challenge was designing an appropriate lift system capable of producing volumes up to 8500 m3/d per well while addressing unknown fluid inflows, fluid transmissibility and recharge, and reservoir-fluid-chemistry characteristics.
Introduction
The Horn River basin is in northeastern British Columbia, approximately 1600 km northwest of Calgary, Alberta (Fig. 1). The primary-target horizons are the Muskwa, Otter Park, and Evie formations, which are predominantly organic and silica-rich shale. Since 2005, slickwater fracture treatments have grown from 400 m3 of water with 10 t of proppant in a vertical well to 29 staged fracture treatments per horizontal well, with each treatment consisting of 5000 m3 of water with 200 t of proppant. As the volume and number of treatments have grown, so has the demand for fracture-treatment water. At 5000 m3/stage, approximately 150 000 m3 of water is required for one horizontal-well completion with 30 fractures. The Debolt formation was identified as a potential water source that could supply the required fracture-treatment water. A test well was drilled to determine reservoir properties and the compatibility of the water with the Horn River fracturing program. Subsequent testing of the Debolt water revealed 21 000 mg/L total dissolved solids, 60 ppm H2S concentration in the water phase, and approximately 5000 ppm of H2S in the vapor phase. The Debolt formation was determined to be underpressured, with a pressure gradient of 7.2 kPa/m.
Seismic Unwired: Cutting the Cable Can Help in Difficult Spots
Authors: Rassenfoss Stephen 
Published: February 2015

Seismic Unwired
David Monk said Apache Corp. uses wireless seismic receivers when it cites advantages over traditional systems connected together by cables.
Examples offered by Apache’s worldwide director of geophysics include a prospect that straddled the border of Argentina and Chile where equipment and radio signals were not allowed to cross; a survey in the shallow waters of the Gulf of Mexico where production platforms would get in the way of streamers used to pick up seismic signals; onshore areas where the cost of crews is high, which is the case in much of the US and Canada; and the Cook Inlet where the extreme environment offshore and onshore made wireless the choice for a number of reasons.
“These things are more efficient systems over more difficult terrain,” Monk said. At the time of the interview nearly all the seismic exploration projects for Apache were wireless.
Eliminating the bright orange or yellow cables reduces the weight of the system, can make it easier to work around obstacles or in difficult waters, and can significantly reduce the profile of seismic exploration in areas where that activity may not be welcome.
A case study by Geospace, a maker of wireless receivers, of a seismic shoot done on the plains of Colombia by Pacific Rubiales Energy Corp., concluded a crew of 21 could lay down the wireless seismic receivers that would have required workers if it had been wired.
And a side-by-side comparison by Apache in the Cook Inlet showed the quality of the seismic data gathered on land was similar for wired and unwired receivers, but wireless performed far better offshore in an area known for its difficult tides and currents.
Apache is a wireless pioneer and is far from the norm in an industry where the largest seismic receiver provider, Sercel, estimates 90% of the seismic channels in use are wired. But the rapid takeoff of wireless receiver sales suggests that is changing.
In most cases one channel, with a geophone that detects the echoes used for underground mapping, is equal to one wireless unit. Wireless multichannel units, though, are a growing part of the market.
Distributed-Temperature-Sensing Method Detects Wax and Optimizes Treatment
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156077, ’Use of Distributed Temperature Sensing for Wax Detection and Treatment Optimization,’ by Manuel Guzman, Brunei Shell Petroleum, prepared for the 2012 SPE International Production and Operations Conference and Exhibition, Doha, Qatar, 14-16 May. The paper has not been peer reviewed.
Distributed temperature sensing (DTS) has been commercially available for more than a decade; however, only recently has it been used in the oil industry. Interpretation of the data has been difficult, and, therefore, its value has been questioned. The author presents an original technique of monitoring wax buildup through the use of the DTS data. Pressure/volume/temperature analysis from an appraisal well showed significant wax content, and DTS provided temperature trends that showed temperature decline in a section of the tubing string. The decline was caused by the additional layer of wax between the crude oil and the gas-filled annulus.
Introduction
DTS has been employed for reservoir monitoring since the 1990s. Application for monitoring on steam-assisted gravity drainage was one of the earlier documented uses. During the last decade, the acquired data have been interpreted for different applications, mainly because of a larger number of installations around the world.
The temperature profile provided for each well in this study has been recorded and is available for evaluation. Nevertheless, current software capabilities allow only qualitative interpretation of the data. Therefore, the time required for monitoring each of the wells is significantly higher than initially expected. Experienced production engineers are required to get the most value out of the large amount of data collected.
During analysis of fluid data from appraisal wells, paraffinic components were identified as part of the crude-oil composition. Several tests were conducted to determine the depositional temperature, and the results showed that wax precipitation could occur along the shallow section of tubing string if the deepest reservoirs were produced alone. However, mixtures of oil from shallow and deep reservoirs reduce the precipitation of paraffinic ends on the tubing string. The field development concept was to produce all four zones simultaneously to minimize wax deposition in the tubing and to install pigging facilities for surface lines.
Reservoir Management for World's First Thermal Gas/Oil Gravity-Drainage Project
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153967, ’A Reservoir Management System for the World's First Thermal Gas/ Oil Gravity-Drainage Project,’ by Keith Rawnsley, SPE, Augustine Ikwumonu, SPE, Solenn Bettembourg, Pristwanto Putra, SPE, and Ibrahim Al-Ismaili, SPE, Petroleum Development Oman, prepared for the 2012 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 16-18 April. The paper has not been peer reviewed.
The world’s first full-field thermally assisted gas/oil gravity-drainage (TAGOGD) project has begun in Oman (Fig. 1). Historically, the field was operated at very high water cut because of aquifer influx through the fractures to the producers. The recovery process was a mixture of gas/oil gravity drainage and water/oil gravity drainage, but the high oil viscosity and low matrix permeability prevented recoveries from reaching more than a few percent. To attempt to unlock the oil in place, a TAGOGD development concept has been piloted in the field over approximately 10 years. This led the way to the full-field project that has now begun.
Introduction
Steam, mainly generated by heat-recovery steam generators, is injected into the natural fractures at the crest of the reservoir, and the fractures distribute the steam in the reservoir. As the oil in the matrix is heated, its viscosity decreases by a factor of 100 and it drains down by gravity through the matrix into the fracture oil rim. From there, it is sent to the production facility (Fig. 2).
The field’s life can be divided into two phases. The first phase, now under way, is the transition period during which the oil rim in the fractures is lowered from its position near the top of the reservoir to a position close to the matrix oil/water contact. This increases the oil column height exposed to TAGOGD to more than 100 m. This period is expected to last approximately 2 years, and production is through gas lifted producers, which are wells inclined 45° to intersect fractures.
The second phase is the plateau/tail period, when the oil rim will be maintained at its deep position. Production in the second phase will be through horizontal producers drilled close to the oil/water contact.
Modeling
The thermal gas/oil gravity process will be the first application of the technique at field scale in the world. Modeling, therefore, has taken and will continue to take a more substantial role than it has in more conventional fields, both to build confidence and to act as an interface between the reservoir surveillance data and opportunity generation. The modeling strategy is designed to ensure that predictions are accurate, to capture ongoing uncertainties, and to improve with experience. As more data become available, the understanding will improve, which will be reflected in changes in the modeling strategy.