bluuebunny/crossref_metadata_2025_split huggingface dataset:
Corrosion Control of Drilling Tools Through Chemical Treatments
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130515, ’Corrosion Control of Drilling Tools Through Chemical Treatments - Effectiveness and Challenges,’ by Nausha Asrar, SPE, Schlumberger, originally prepared for the 2010 SPE International Conference on Oilfield Corrosion, Aberdeen, 24-25 May. The paper has not been peer reviewed.
Increasing production is challenging because the wellbore fluids in many new fields are typically multiphase with harsh chemical compositions and conditions, such as high hydrogen sulfide (H2S), carbon dioxide (CO2), and occasionally dissolved oxygen, in a high-temperature/high-pressure environment. All this makes corrosion control a major concern, especially in the present challenging economic climate, where the risks and cost associated with corrosion may have significant impact on health, safety and the environment; on capital expenditure; and on operation expenditure.
Introduction
Domestic oil and gas production is considered a mature industry in the USA because most of the significant available reserves have been identified and are being exploited. Direct corrosion costs associated with this activity are estimated to be approximately USD 1.4 billion, with USD 0.6 billion attributed to surface-piping and facility cost, USD 0.5 billion to downhole tubing, and USD 0.3 billion to capital expenditures related to corrosion.
Corrosion is defined formally as the destruction of metal by direct chemical reaction or by an electrochemical reaction of a metal with its environment. Chemical corrosion is the direct combining of a metal with another material, and it usually occurs at higher temperatures. Corrosion of this type seldom occurs in drilling, except in very-high-temperature wells. The second, more common type of corrosion electrochemical, occurs at a solid/liquid interface. This arises in nearly every instance where water or brine contacts metal/alloy equipment. Therefore, electrochemical corrosion is the principal concern in drilling operations.
Drillpipe probably is the most harshly treated of all equipment at the rigsite. While a well is being drilled, the drillpipe is exposed to high stresses, and it is exposed to both formation fluids and drilling mud. Thick-walled drillpipes are called drill collars. They contain electronic chassis and other measurement tools on the annular side and provide weight to the bit for drilling. These drillpipes are made of hardened high-strength steel and are likely to suffer from fatigue and different types of corrosion started from deep corrosion pits caused by corrosives, either from the mud itself or from being stacked wet. Also, the high hardness and strength of the drill-collar materials makes such collars more susceptible to stress corrosion cracking (SCC).
Corrosion Mechanisms
Corrosion encountered in drilling operations involves several mechanisms that have been grouped into (1) electrochemical corrosion, and (2) mechanical/corrosive effects.
Technology Focus: EOR Operations (June 2011)
Authors: Bonet-Cunha Luciane 
Published: February 2015

Technology Focus
Enhanced oil recovery (EOR) is not new. There are many areas of the world where most of the oil is produced by use of EOR techniques. Among possible options, the predominant EOR methods in use to recover oil left behind are thermal, CO2-injection, and chemical-injection methods. However, despite many developments and successful implementations, EOR is still risky. Well-known areas for technology development that will boost EOR-project results include robust reservoir modeling, reliable reservoir-surveillance/-monitoring technologies, and efficient operations to minimize operational costs.
Regarding technical publications, during the past year, more than 350 papers with the main focus on EOR were presented at various SPE events. Topics explored in several of them relate to enhancements associated with the three key areas mentioned above. One new important point described in many papers refers to extending the use of smart-field technologies to EOR, aiming at continual optimization of oil and gas production in a certain field. To achieve this optimization, it is imperative that data gathered in the operational phase be applied to improve the quality of the associated reservoir models used for management in a fast and reliable manner, leading to so-called closed-loop reservoir management.
This month, the featured papers address many challenges found in EOR operations. Papers selected present interesting and successful field-development projects under way throughout the world. Also emphasized is the importance of bringing in and applying novel ideas, such as the smart-field concept, to solutions of EOR challenges.
EOR Operations additional reading available at OnePetro: www.onepetro.org
SPE 132626 • “Ensemble-Based Optimization of EOR Processes” by Uchenna O. Odi, SPE, Texas A&M University, et al.
SPE 132774 • “Improved Polymer-Flood Management Using Streamlines” by Torsten Clemens, SPE, OMV, et al. (See SPE Res Eval & Eng, April 2011, page 171.)
SPE 139851 • “Tengiz Sour-Gas-Injection Project” by Sabyrzhan Darmentaev, SPE, Tengizchevroil, et al.
Polymer Injection in a Deep Offshore Field - Angola, Dalia/Camelia Field Case
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 135735, ’First Polymer Injection in a Deep Offshore Field - Angola: Recent Advances on Dalia/ Camelia Field Case,’ by Danielle Morel, SPE, and Michel Vert, Total E&P; Stephane Jouenne, SPE, Total Petrochemicals; and Renaud Gauchet and Yann Bouger, Total E&P Angola, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
Key challenges of the polymer-injection project in the Dalia field, offshore Angola, were to start polymer injection:
Very early in the field development
With much wider well spacing than in other projects
Under high-salinity conditions (&gt;25g/L)
With specific logistics of a remote deep offshore area
Introduction
The Dalia field is 130 km offshore Angola, with an estimated 1 billion bbl of recoverable oil. Water depth varies between 1200 and 1400 m, with reservoirs 800 to 1000 m below the seabed. Very-high-quality 3D-seismic data enabled mapping of the main reservoir structure, including sands and clay areas only 6 to 10 m thick. The channel complexes can be as thick as 100 m but are divided into heterogeneous sections with alternating layers of oil sands and clays. Permeability ranges from a few hundred millidarcies to several darcies, with an average permeability greater than 1 darcy. The reservoir temperature ranges from 45 to 56°C, and reservoir pressure is 215 to 235 bar. The 19 to 38°API oil is slightly undersaturated, with viscosity ranging from 1 to 11 cp at reservoir conditions. Water viscosity is approximately 0.5 cp at reservoir conditions.
The field produces by energy from water injection, using a floating production, storage, and offloading (FPSO) vessel with 31 deviated or horizontal subsea injector wells and four injection flowlines. Generally, a single flowline is used to inject into several reservoirs and several systems. Maximum water injection is 405,000 BWPD. Production is achieved through four production lines and 37 producers. First oil was on 13 December 2006. The 240,000-BOPD plateau rate was reached after a few months and has been maintained since.
Seawater is desulfated to prevent risk of barium sulfate deposit, and has been injected from the start. Produced water will be reinjected after water breakthrough. By June 2010, 25 producer wells were connected and water breakthrough had occurred in several wells, with water cut ranging from a few percent to more than 40%. The current water-injection salinity is approximately 50 g/L.
Downhole Fiber Optics Are Changing the Well's Footprint
Authors: Powers Greg 
Published: February 2015

Guest editorial
“Ephemeralization” is the term coined by engineer Buckminster Fuller, the father of the geodesic dome and an early environmental activist, to describe the advancement of technology that achieves “more and more with less and less until eventually you can do everything with nothing.”
This idea of doing more with less is at the heart of advances in downhole fiber-optic technology, and, in relative terms, its application is not far removed from doing nearly everything with almost nothing.
Using light-transmitting optical fibers slightly thicker than a human hair and similar to the technology that brings Internet capacity to your home, we have been measuring wellbore parameters such as temperature, pressure, strain, vibration, and sound (acoustics) for years. In the near future, with the development of new optical or photonic sensing methods for chemical, microdeformation, resistivity, magnetic field, and other monitoring solutions, the industry will be able to integrate, visualize, and analyze numerous operations and activities downhole in real time, thus extending the life of the well and the reservoir.
More Photons, Fewer Electrons
Fuller illustrated his concept of ephemeralization by comparing the tons of copper wire required for a trans-Atlantic communication cable that could be replaced with ounces of the copper wire that it takes for a single communications satellite. With fiber-optic cables, the comparison is equally dramatic in many ways.
Legacy electronic systems require deployment of complex, dedicated downhole instruments with millions of transistor junctions to make discrete wellbore measurements at specific points and times. In marked contrast, fiber-optic technology uses low-cost, low signal loss, high-bandwidth, silica glass transmission lines down-hole in concert with surface optoelectronic instruments to continually acquire real-time, remote, fully distributed measurements over the entire length of the installation, making the solution highly scalable.
Leaving instrumentation on the rig floor, and not within the wellbore, removes risk from the hostile environment and enhances operating parameters. For instance, fiber-optic sensing and monitoring have been used in environments of up to 300°C (572°F) for years with great success. Solutions exist today for much higher temperatures. In contrast, electronic solutions are limited to less than about 200°C (392°F) for permanent deployment.
As the technology evolves, surface instrumentation can be upgraded and connected to the same downhole fiber-optic sensors, instantly providing better data and potentially new sensing applications. For example, instrumentation connected to fiber-optic cables originally deployed on pipelines for telemetry decades ago is now being used to monitor distributed flow, temperature, acoustics, and tubular strain across many kilometers, thus enabling leak detection, flow restriction identification, object tracking, and other capabilities.
Stage Multiplier Technology Provides Ultrahigh Stage Numbers
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
In December 2011, a record-setting 60-stage openhole fracturing system was installed in the Marcellus Shale in western Pennsylvania. One of the key technologies that enabled this application is a new stage multiplier device called the Packers Plus RepeaterPORT sleeve, which allows the same sized ball to be dropped multiple times. Initially, reservoir fracture modeling indicated that a relatively small number of planar fractures would adequately drain unconventional resource plays such as shale and ultratight rock for both oil and gas. However, empirical evidence has shown that this is not the case. No matter which completion technique is used, stage numbers have been increasing and spacing between fractures has been decreasing. In many cases, however, operational efficiencies are nearing an economic limit for conventional cemented liners and plug-and-perforation completions.
Long planar fractures may not be the best approach to effective resource recovery; instead, shorter fractures, smaller fluid volumes, and higher stage numbers have increased productivity and ultimate recovery numbers by as much as 50%. In addition, liquids and condensate numbers (bbl condensate/MMcf/D of gas) increase with openhole completions and ultrahigh stage density.
Technology Description
The stage multiplier technology operates by allowing the ball to pass through the port, putting it through a passive shift that does not open the port but instead moves it to the next operating position. Subsequent balls of the same size will either provide another passive shift or prime the port to be opened with the next ball. In the latter case, the ball will move the port to an active shift position allowing the next ball to shift it to the open position.
This technology creates a number of advantages. First, the ability to run the same size ball multiple times enables an increase in stage numbers—currently up to 60 stages in 5½-in. casing. A second advantage is that the smallest port size can remain relatively large compared with other approaches, reducing accumulated friction from fluid passing through multiple port restrictions. In addition, access with coiled tubing is enhanced for operations such as production logging and well cleanout. Third, operational efficiency is greatly enhanced by allowing uninterrupted stage-to-stage advancement. Furthermore, pumping rates can be reduced, saving on hydraulic horsepower and equipment requirements, because single intervals are being treated per stage rather than three or four perforation clusters. This means that the effective rate will be similar for individual intervals, but the total pump rate at surface can be reduced by approximately one-third, thus saving on surface treating pressure and friction while pumping.
Knowledge Management In the Digital Age
Authors: Hubert Cindy 
Published: February 2015

Management
The project challenges of the oil and gas industry are characterized by change and uncertainty. Work operations span the globe and smooth working partnerships cannot be anticipated. However, we can confront that uncertainty by becoming more agile. Greater levels of agility rest upon using the power of knowledge—the cornerstone of successful corporations.
The difference between a powerful knowledge management (KM) program and the also-ran is the ability to identify and enable critical knowledge. The KM system is a tool and not the end product. People still make the system work and are the critical component for input, expert collaboration, and mentoring. In fact, business value is created when critical knowledge gets to the right person at his or her teachable moment and is applied. The crucial knowledge set within your organization is often hidden—sometimes buried—because it resides in people or in many electronic reports or in stacks of lessons learned. The question we need to ponder is this: Can too much knowledge flow?
What Is Knowledge Management?
From a practical perspective, knowledge is information in action. Until people take information and use it, it is not knowledge. In a business context, knowledge is what employees know about their customers, each other, products, processes, mistakes, and successes, whether that knowledge is tacit or explicit.
The American Productivity and Quality Center (APQC) defines KM as a systematic effort to enable information and knowledge to grow, flow, and create value. The discipline is about creating and managing the processes to get the right knowledge to the right people at the right time and help people share and act on information in order to improve organizational performance. Organizations implement a KM program to institutionalize and promote knowledge sharing practices. An enterprise program is usually a centralized, organizationwide effort to standardize and excel in KM.
Strategy in a New Context
The defining book on how to implement an effective KM strategy was written in 1998 when the discipline was less than a decade old (If Only We Knew What We Know by C. O’Dell and C.J. Grayson). Since then, we have seen many momentous changes affecting KM: rising Internet and broadband access, the explosion of mobile devices and smartphones, the continued rise in virtual work and global teams, the international equalization of competitive prowess and knowledge, the decline of readership for the printed word, the rise of digital readership, and so on. It would be hard to overstate how profoundly these developments have both challenged and enhanced the promise and practice of KM. The core objectives have not changed, but how we accomplish them has.
Technology Focus: Coiled Tubing Applications (June 2012)
Authors: Misselbrook John 
Published: February 2015

Technology Focus
The coiled-tubing (CT) industry has experience unparalleled growth in the past year, driven directly by the massive expansion in multistage-fracturing operations in North America. Various sources estimate that the US consumed 50% of the world’s CT in the past 12 months, helping to contribute to a massive 80% growth in product coming off the CT production lines.
The growth in the United States was fueled primarily by three applications: milling out composite plugs, milling out fracture-sleeve ball seats, and toe shoots (the name given to the first perforating operation before plug-and-perforate operations). Because toe shoots take place without any pressure on the well, the amount of CT life consumed by fatigue during the operation is small. Plug or seat milling, on the other hand, takes place after fracturing operations are complete and with the wellbore fully pressure charged by the formation; therefore, the CT life consumed by fatigue is high. Superimposed over the wellbore pressures are the pressures arising from circulating fluids through the CT and the milling assemblies. In some of the higher-pressure shale plays, CT strings last only for a few jobs.
Accordingly, any technology that reduces the superimposed pressure could lead to longer CT life and potentially to lower completion costs. Two of the papers selected for this month’s issue involve new technologies that might be helpful to operators in this respect.
However, of possible greater concern to CT companies in North America is the fact that CT use is now clearly dominated by well-completion operations, or, to put it another way, by rig count. Until recently, the CT intervention business was primarily remedial in nature and, thus, was partially cushioned from the extreme cycles experienced by drillers. However, in North America, a change has already arrived and, with gas prices at historic lows, CT service companies, CT pipe manufacturers, and CT equipment manufacturers probably need to prepare for the same swings that the rest of the well-construction industry is used to.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 152351 Comprehensive Approach to Production Stimulation of Massive Cold Heterogeneous Carbonate Formation Using Coiled Tubing by Vladimir Dnistryansky, Schlumberger, et al.
SPE 154221 Production Logging on Coiled Tubing in a Marcellus Shale Horizontal Completion by A. McCluskey, Shell Exploration and Production
SPE 154060 Best Practices for Composite Plug Milling by Steven Craig, Baker Hughes, et al.
SPE 154423 Use of Coiled Tubing Deployed Expandable Technology in Sidetrack Drilling Operations by A. Caccialupi, Mohawk Energy, et al.
Coiled Tubing Reduces Stimulation Cycle Time by More Than 50% in Multilayer Wells in Russia
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154386, ’Coiled Tubing Reduces Stimulation Cycle Time by More Than 50% in Multilayer Wells in Russia,’ by A. Yudin, SPE, K. Burdin, and D. Yanchuk, SPE, Schlumberger; and A. Nikitin, SPE, I. Bataman, A. Serdyuk, N. Mogutov, and S. Sitdikov, SPE, Rosneft, prepared for the 2012 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed.
Traditionally, coiled tubing (CT) has had very limited service diversity in Russia. Its use has been mostly limited to wellbore cleanouts and nitrogen kickoffs after fracturing treatments. CT equipment and technologies were used to supplement stimulation operations in one of the world’s largest oil fields, Priobskoye, which has up to five separate layers per well. Conventionally, well completions at Priobskoye have involved complicated workover operations with tubing, packers, and wireline perforation after each stimulated layer. An average well with three layers took 30 days to complete. CT provided a significant improvement in completion efficiency, reducing the cycle time to just 10 to 12 days.
Introduction
Priobskoye is one of the world’s biggest oil fields. It is in the Khanty-Mansi autonomous region, and the Ob river divides it into two parts, the left bank and the right bank.
Hydraulic fracturing is the main method used to increase production and recovery from the Priobskoye formations, and most new wells are stimulated immediately after drilling. Fracturing optimization has mostly evolved toward increasing the quality of hydraulic fractures. However, the Priobskoye field is a multilayer reservoir where separate fracturing treatments normally take excessively long times to complete. The standard completion method has consisted of a sequential approach of the workover crew perforating, the wireline crew running in tubing and packers, and the fracturing crew fracturing and pulling tubing and packers out of hole for each of the layers. That sequence takes a long time to complete the well, especially if the formation starts flowing naturally before the workover and wireline crews can manage the pressure properly to continue operations.
Starting in 2008, CT fleets were employed to assist in the well-completion cycle with abrasive perforating and well-cleanout operations under pressure between the fracturing stages. The advantage of CT lies in its ability to perform the same sequence of operations significantly faster. In fact, the CT replaced both workover and wireline rigs, with the perforating performed with an abrasive material jetted through the nozzles of a special bottomhole assembly. A jet’s velocity and its focused flow create a hole inside the casing and a cavern inside the cement and the rock outside the casing (Fig. 1).