Duoline

DUOLINE® Technologies Announces The Development Of A Higher Temperature Resistant Product: D-350

2012-02-17T12:16:00.000-08:00

D-350 provides reliable corrosion protection of steel tubulars with temperature resistance up to 350°F/177°C.

DUOLINE® Technologies--- the global leader in fiberglass internal lining systems for protecting oilfield tubulars --- is proud to announce the development of a higher temperature resistant product: D-350. D- 350 provides reliable corrosion protection of steel tubulars with temperature resistance up to 350°F/177°C.Benefits of DUOLINE® D-350 :•Reliable temperature resistance up to 350°F (177°C) •Proven to maintain mechanical and chemical resistance similar to that of Duoline®Technologies’ successful D-20 lining system. •Consists of a seamless glass reinforced filament wound liner wrapped in a continuous helical pattern to provide the greatest tensile and hoop strengths. •Glass is saturated during the winding process with a proprietary aromatic amine resin formulation providing fusion between the fibers. This ensures a holiday-free, flawless liner. •Saturation of fibers with resin provides chemical resistance required to prevent corrosion attack of the steel tubulars.•Liners are cured by applying internal heat to a hollow mandrel. This ensures that encapsulated air pockets do not occur on the liner’s bodywall, a major differentiation from liners produced using a thermal cure cycle which cures the outer diameter first and increases the potential for product failure by encapsulating air pockets on the liner’s bodywall.Duoline-20®, manufactured by DUOLINE® Technologies, is a filament-wound fiberglass-reinforced epoxy liner that reliably beats corrosion. Since 1964 more than 100 million feet have been successfully installed world wide as a more robust alternative to plastic coatings, and as a high-performance, high-value, cost-effective alternative to Corrosion Resistant Alloys. Duoline® is ideally suited for diverse applications such as but not limited to offshore platforms, onshore work-over rigs, sour gas service, oil and gas producing wells, waterflood injection wells, brinewater/chemical disposal wells, CO2 injection wells, saltwater disposal systems.For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.comOr visit:

New Study Shows No Evidence of Groundwater Contamination from Hydraulic Fracturing

2012-02-17T12:09:00.000-08:00

Assessing the Real and Perceived Consequences of Shale Gas DevelopmentThe astonishing surge in domestic natural gas production, brought on by the widespread use of hydraulic fracturing and horizontal drilling, has transformed the outlook for U.S. energy. Conservative estimates project the use of these techniques in shale gas development will all but assure a clean and affordable natural gas supply for generations to come, creating new jobs and enhancing our nation’s energy security.That sanguine view has been tempered, however, by concerns that hydraulic fracturing may contaminate groundwater and pose other threats to public health. While little evidence exists directly linking the practice to environmental harm, such fears have ignited a controversy that has dominated public discourse on the issue. In fact, some areas have halted shale gas development altogether, at least temporarily.In response, the Energy Institute at The University of Texas at Austin funded an independent study of hydraulic fracturing in shale gas development to inject science into a highly charged emotional debate.For this study, the Energy Institute assembled an interdisciplinary team of university experts to examine a broad array of issues associated with hydraulic fracturing in three prominent shale plays — the Barnett Shale, in north Texas; the Marcellus Shale, in Pennsylvania, New York and portions of Appalachia; and the Haynesville Shale, in western Louisiana and northeast Texas.The Energy Institute team investigated an array of issues related to shale gas development, including groundwater contamination, toxicity of hydraulic fracturing fluids, surface spills, atmospheric emissions, water use, drilling waste disposal, blowouts, and road traffic and noise.The goal of this research is to provide policymakers a fact-based foundation upon which they can formulate rational regulatory policies that ensure responsible shale gas development.Fact-Based Regulation for Environmental Protection in Shale Gas DevelopmentFor this study, the Energy Institute at The University of Texas at Austin assembled a team of experts with broad experience and expertise, from geology and environmental law to public affairs and communications. In addition to university faculty, the Environmental Defense Fund was actively involved in developing the scope of work and methodology for this study, and reviewed final work products.Dr. Charles GroatUnder the leadership of Institute Associate Director Dr. Charles “Chip” Groat, researchers examined three critical areas related to shale gas development:Environmental and health effects related to all phases of shale gas development in the Barnett, Marcellus and Haynesville shale plays, including hydraulic fracturing, groundwater contamination and air emissions. Where problems were reported, researchers determined the actual cause of problems, based on a review of scientific and other literature.Public perceptions of shale gas development and hydraulic fracturing, as well as the tone of popular media — positive, negative, or neutral.State and federal regulations related to shale gas development, including an analysis of individual states’ capacity to enforce existing regulations.“Our mission is to alter the trajectory of public discourse in a positive manner, as exemplified in our credo — good policy based on good science.” - Dr. Raymond L. Orbach, Director, Energy Institute, The University of Texas at Austin.Video Clips Featuring UT ExpertsDr. Raymond L. OrbachIn these clips, Drs. Orbach and Groat discuss preliminary findings from the Energy Institute’s study on hydraulic fracturing: “Fact-Based Regulation for Environmental Protection in Shale Gas Development.”Click on the following video clips to view:Overview on Hydraulic Fracturing in Shale Gas Developmenthttp://www.utexas.edu/opa/video/media/energy_institute/aaas_clips.preview.mp4Dr. Raymond L. Orbach, Director, Energy Institute, University of Texas at Austinhttp://www.utexas.edu/opa/video/media/energy_institute/orbach_ray_all.preview.mp4Dr. Charles "Chip" Groat, Associate Director, Energy Institute, University of Texas at AustinThe following is an overview of key findings from the Energy Institute’s study.http://www.utexas.edu/opa/video/media/energy_institute/groat_chip_all.preview.mp4Scientific Investigation into Groundwater Contamination and Other Environmental ImpactsThe public debate over hydraulic fracturing in shale gas production has been marked by fears that the process will contaminate groundwater. Concerns also have been raised that underground methane releases are contaminating water wells.Though little scientific evidence exists to support such claims, policymakers in some areas have banned the practice, and others have imposed moratoriums on shale gas development until additional research is conducted.For this report, the Energy Institute research team focused on reports of groundwater contamination and other environmental impacts of shale gas exploration and production in states within the Barnett, Marcellus and Haynesville shales.Key Findings:Researchers found no evidence of aquifer contamination from hydraulic fracturing chemicals in the subsurface by fracturing operations, and observed no leakage from hydraulic fracturing at depth.Many reports of groundwater contamination occur in conventional oil and gas operations (e.g., failure of well-bore casing and cementing) and are not unique to hydraulic fracturing.Methane found in water wells within some shale gas areas (e.g., Marcellus) can most likely be traced to natural sources, and likely was present before the onset of shale gas operations.Surface spills of fracturing fluids appear to pose greater risks to groundwater sources than from hydraulic fracturing itself.Blowouts — uncontrolled fluid releases during construction or operation — are a rare occurrence, but subsurface blowouts appear to be under-reported.Regulation of Shale Gas DevelopmentResearchers surveyed federal and state laws and regulations related to shale gas development in 16 states that have or are expected to have shale gas production. This analysis covered all major phases of the shale gas lifecycle — exploration, well siting, drilling and fracturing, production, well plugging, and site closure.The research team also examined several exemptions of shale gas development from federal environmental laws, including the Resource Conservation and Recovery Act, the Comprehensive Environmental, Response, Compensation, and Liability Act, the Clean Water Act, and the Safe Drinking Water Act.Key Findings:Primary regulatory authority for shale gas is at the state level, and many federal requirements have been delegated to the states. Most state oil and gas regulations were written well before shale gas development became widespread.Some states have revised regulations specifically for shale gas development, with particular focus on three areas of concern:Disclosure of hydraulic fracturing chemicalsProper casing of wells to prevent aquifer contaminationManagement of wastewater from flowback and produced waterGaps remain in the regulation of well casing and cementing, water withdrawal and usage, and waste storage and disposal.Regulations should focus on the most urgent issues, such as spill prevention — which may pose greater risk than hydraulic fracturing itself.Enforcement of State RegulationsResearchers also reviewed state agencies’ enforcement capabilities, including a review of staff responsible for conducting inspections and attorneys supporting enforcement. The review covered violations recorded, enforcement actions, field sampling, and monitoring.Key Findings:Enforcement capacity is highly variable among the states, particularly when measured by the ratio of staff to numbers of inspections conducted.Most violations recorded are of the type associated with conventional gas drilling rather than being specific to hydraulic fracturing and shale gas production.Enforcement actions tend to emphasize surface incidents more than subsurface contaminant releases, perhaps because they are easier to observe.http://energy.utexas.edu/index.php?option=com_content&view=article&id=151&Itemid=160

Composite Industry People's Choice Award

2012-02-10T16:11:00.000-08:00

People’s Choice Awards – Voice Your OpinionTell The Composites Industry Which 2012 Award Entries are Your Favorite! NEW THIS YEAR — Browse this year’s submissions and visit the Awards Voting Poll to cast your opinion for the People's Choice for best entries. More than 40 companies entered their latest innovations to compete in this year’s Awards for Composites Excellence (ACE) and Pinnacle Awards (for the cast polymer industry) hosted by ACMA and presented at COMPOSITES 2012. Don’t miss the chance to see these products up close in the Awards Pavillion and to hear which ones are named ACE and Pinnacle winners at Wednesday's highly attended Awards Luncheon. Vote for one of our corporate family members: Stahlin Non-Metallic Enclosures Under the Infinite Possibility for Market Growth Categoryhttp://www.acmashow.org/awards_voting.cfm

Convidamos você com prazer a se unir ao Duoline® Technologies Group

2012-02-03T06:40:00.000-08:00

A leitura desta breve introdução levará somente 30 segundos --- nosso compromisso é que esse meio minuto represente um grande valor para você!Convidamos você com prazer a se unir ao Duoline® Technologies Group. A abrangência deste grupo cobre não somente a Duoline® Technologies, mas todos os campos associados, tais como: engenharia de acabamento, prevenção da corrosão de tubulações, materiais de construção, novos produtos e importantes anúncios da indústria. O alcance geográfico da firma Duoline® Technologies Group cobre a América do Norte, a América Latina, o Reino Unido, a Europa Oriental e Ocidental, o Oriente Médio, a África e a Ásia/ Pacífico. Basta clicar no link e unir-se à discussão: http://www.linkedin.com/groups?gid=3725428&trk=hb_side_gNão tem interesse? -Não há problema. No entanto, por gentileza considere visitar o nosso site para baixar a documentação: "Glass Reinforced Epoxy Lined Tubing Proven to be an Alternative to Corrosion Resistant Alloys" (Tubulação revestida de epóxi reforçada de vidro, comprovada como uma alternativa às ligas resistentes à corrosão) no endereço: http://www.duoline.com/inside_pipeline_club.cfmObrigado pelos 30 segundos!pipe liner, oil, gas, shale,white paper, plastic, CRA, coated pipe

Mitigating Corrosion in the Oil and Gas Industry

2012-01-27T06:18:00.000-08:00

By: Kent Caudle/Champion TechnologiesJanuary/February 2011Most Americans think of corrosion in the context of fretting about one of the many old pipelines snaking beneath or near their communities exploding without warning or suddenly releasing hazardous substances into the environment — and who can blame them?Catastrophic failures of large-diameter pipelines transporting crude oil, natural gas and petroleum products are front-page news, especially when fatalities are involved. A recent front-page article in the Houston Chronicle proclaimed the snarl of pipelines underlying the coastal Texas city to be a “hidden menace,” with some old pipeline systems unwittingly constructed using inferior welding techniques or covered with protective coatings the industry learned later could actually make pipelines more susceptible to corrosion.Decades of hands-on experience and solution-focused R&D have enabled corrosion inhibitors to meet and resolve new challenges.Most workers in the upstream oil and gas industry appreciate how serious corrosion issues can become for production and processing operations, as well. Production tubing and equipment, processing equipment, separators, pumps and flow lines -- wellsite facilities are literally at risk during every step in the production-handling process.Corrosion has been a problem in the domestic oil and gas industry since at least the 1930s, when corrosion-related issues were reported mainly in low-pressure oil-production systems; although they were apparently neither widespread nor of serious economic concern. But the industry learned quickly that corrosion is driven by many mechanisms. So as domestic oil and gas activity expanded after World War II and throughout the latter half of the 20th Century, corrosion problems became more common and more severe.For the complete article visit:http://wellservicingmagazine.com/mitigating-corrosion-oil-and-gas-industryFor your internal fiberglass pipe lining needs for corrosive environments visit:http://www.duoline.com/

Duoline "DL-Ring"

2012-01-20T06:20:00.000-08:00

A unique corrosion barrier system enabling placement of GRE internal liners inside any shoulder-to-shoulder premium thread without the need for a special coupling!THE CHALLENGE: To provide superior internal corrosion protection using a Glass-Reinforced-Epoxy (GRE) lining system with any unmodified free-issue premium threaded tubing or casing.THE SOLUTION: IN TWO EFFECTIVE STEPS: 1. Use DUOLINE® from Duoline Technologies: a premium internal corrosion resistant lining system for oilfield steel tubing and line pipe. DUOLINE® is proven to be wireline abrasion and chemically corrosion resistant in both controlled laboratory testing and through successful performance in more than 75,000,000 feet of downhole application. 2. Use Duoline Technologies new DL-RING patent pending connection technology that permits the lining system to accommodate any proprietary Premium Connection. HOW DOES THE DL-RING WORK? Two DL-flares place the DL-CBR in compression during field make-up.The unique concept and material composition has been used extensively and successfully in downhole completions with DUOLINE® tubing in numerous other 'FGL' versions of unmodified premium and API connections.http://www.duoline.com/ContentGather.cfm?navid=3&sublinkid=70

STW Resources Holding Corp. will commission an oilfield pilot project to process produced water.

2012-01-10T17:26:00.000-08:00

The pilot program in Permian Basin (Texas) will process approximately 21,000 gallons or 500 barrels per day per siteSTW Resources Holding Corp., a water reclamation services company, announced that it will commission its first oilfield-produced water processing pilot in the Permian Basin of West Texas .STW Resources will deploy a specialized mobile unit, designed and built using patented and proprietary technologies, to process up to 500 barrels per day for up to 10 days per site. STW Resources anticipates that it will perform at least five pilot projects of various duration for different oil companies within a 30-day period.STW Resources' pilot equipment is engineered and operated by Bob Johnson & Associates, one of STW's engineering partners. Pilots represent the final phase required to procure water reclamation contracts from oil and gas customers. STW Resources' technology cleans produced and/or "brackish water" (water that has more salinity than fresh water, but not as much as seawater) from underground aquifers to operator's various specifications required in the drilling and fracking operations of oil and gas wells. This technology is capable of removing sulfates, hydrocarbons, iron, magnesium, H2S, and any other contaminants. Further removal of chlorides, from brackish water, results in potable water suitable for human consumption. This water, previously not utilized, is being introduced into the ecosystem by the company; the processed water will be re-used by the operator for their drilling and/or fracking operations.For more information go tohttp://www.stwresources.com http://www.rimbach.com/scripts/Article/PEN/Number.idc?Number=499

IPAA Announcement

2012-01-06T15:04:00.001-08:00

IPAA AnnouncementPOSTED BY ADMIN ON DEC 19, 2011 IN NEWS ARCHIVES | 0 COMMENTSTO: All Permian Basin IPAA Member CompaniesOn December 6, the Independent Petroleum Association of America (IPAA) emailed important information to all IPAA members concerning the new EPA reporting requirements for Greenhouse Gases, requiring action by virtually all oil and natural gas producers by January 3, 2012 in order to avoid more stringent reporting requirements in future years. Last Friday, the Permian Basin Petroleum Association, as part of its strong working relationship with IPAA, sent IPAA’s information to all its members, conveying the same urgency. There is a lot of useful information attached to IPAA’s Dec.6 email on this subject, which can also be accessed through the PBPA’s recent email. Registering with EPA’s e-GGRT site is relatively straightforward. To access some of the other links requires right-clicking on individual items, then clicking on “open hyperlink.” IPAA also has a link on its web site to help producers navigate through the recent changes in reporting and compliance with SPCC plans which were finalized this year. It is practical information like this, together with the intensive lobbying that IPAA does in Washington to minimize the extent and ultimate financial impact of these regulations, that makes your investment in IPAA absolutely invaluable. The same can be said of PBPA and its efforts in both Austin and, increasingly, in Washington. I am frequently baffled when I visit with independent producers who say they don’t see the benefits of paying as little as $450 a year for IPAA membership. What is described above only scratches the surface of what IPAA and PBPA provide in the way of value to their members. So, next time your IPAA and/or PBPA membership renewal comes due, smile when you write the check, realizing that this is the biggest bargain you will get this year. You might even consider moving your membership to a higher level to help fight these never-ending regulatory and tax issues. After eight years as Regional Director for IPAA- Texas Permian, I am term limited and have handed the reins over to Jeff Sparks with Discovery Operating Company. Discovery and the Sparks family have a long association with IPAA, and you’ll be in good hands. Merry Christmas!http://pbpa.info/category/news-archives/

Top 5 Rig Managers Ordering for Newbuilds

2011-12-30T08:01:00.000-08:00

#1 Noble Drilling ordered eight offshore drilling units during 2011. Four drillships, each being rated to work in water depths up to 12,000 feet, were ordered from Hyundai Heavy Industries in South Korea. Noble currently has seven deepwater units under construction, including the four ordered this year, with delivery dates ranging from late 2011 through the end of 2014. Upon delivery of the deepwater units that are currently under construction, Noble's deepwater fleet will consist of 28 units.Noble also placed orders with Jurong Shipyard for four jackups. Each jackup is rated to work in water depths up to 400 feet. Currently, Noble has six jackup units under construction, including the four ordered this year. Delivery dates for the six jackups range from late 2012 to 2014. Noble's jackup fleet will consist of 49 units upon delivery of all jackups that are currently under construction.#2 n 2011, Petrobras and Estaleiro Atlantico Sul joined forces to create Sete Brasil to meet Petrobras' need for pre-salt drilling activities. According to the company, it intends to build 7 deepwater rigs. The rigs are being built in Brazil and will be rated to work in water depth up to 10,000 feet. Delivery dates for the rigs are expected between early 2015 and early 2018.#3 Maersk Drilling placed orders for six offshore drilling units during 2011. Four drillships were ordered from Samsung Heavy Industries in South Korea with each being rated to work in water depths up to 12,000 feet. Delivery dates range from late 2013 through late 2014. Delivery of these newbuilds will bring Maerk's deepwater fleet to a total of nine.Maersk has also placed orders for two jackups from Keppel FELS Shipyard in Singapore. The jackups will be rated to work in water depths up to 492 feet. Currently, Maersk's jackup fleet consists of 12 units with all being rated to work in water depths greater than 350 feet.#4 Standard Drilling was founded in December 2010 as a pure play premium jackup company. The company ordered six jackups from Keppel FELS shipyard in Singapore in 2011 on spec. Delivery of the first unit is expected in early 2013. All units will be rated to work in water depths up to 400 feet.#5 Transocean placed orders for five offshore drilling units during 2011. Two ultradeepwater drillships were ordered from Daewoo Shipbuilding & Marine Engineering in South Korea, each rated to work in water depths up to 12,000 feet. These orders were added to the fleet as part of the Aker Drilling acquisition in 2011 and are the only two deepwater units Transocean has under construction. The company elected not to exercise the option for the construction of two additional units. Transocean's deepwater fleet currently consists of 75 units. challenges ahead.Transocean also ordered three jackups in 2011 from Keppel FELS in Singapore. Each jackup is rated to work in water depths up to 350 feet. Transocean's jackup fleet currently has 60 units, not including the three ordered this year. The anticipated delivery date for the jackups is September 2013.Data from Rigzone: http://www.rigzone.com/news/article.asp?a_id=113414

Sour gas pipelines – how do we deal with them?

2011-12-21T04:35:00.000-08:00

BY EUR.ING. DAVID NEWMAN, MANAGING DIRECTOR, INTERNATIONAL PIPELINE MANAGEMENT SERVICES LTD, UKPipelines International — December 2011Sour gas is evident in various oil and gas producing regions of the world, in particular, the Middle East and the Commonwealth of Independent States. The product can not only cause deterioration to pipelines, but is potentially harmful to the environment and personnel health. This calls for specific requirements in terms of steel manufacture, materials selection and testing, as well as a strict code of compliance.The detrimental effects as a result of sour service can range from small pinhole leaks to catastrophic failure in pipelines owing to a number of phenomena as a result of the sour gas environment, namely: stress corrosion cracking, sulphide stress corrosion cracking, hydrogen-induced cracking, hydrogen embrittlement and exfoliation, and sulphide-oriented hydrogen-induced cracking.Mitigation and/or control of cracking in sour gas pipelines can be approached in a number of ways, namely steel manufacturing control, materials and fabrication processes, controlling the environment, and isolating the components from the sour environment.Mitigation at the design stageMitigation must start at ‘square one’ – namely, materials selection, which requires careful review, testing and control such that they will be stipulated as ‘fit-for purpose’ for sour service. The materials selection process should reflect project-specific requirements, intended design life, costings, failure evaluations as well as environmental considerations, etc. As an absolute minimum, the following should be taken into consideration:Article continues below… Design life and system availability;Pipeline system design – avoidance of deadlegs to mitigate stagnant conditions, correct pipeline sizing to reduce water hold ups and solids deposition;Facilities and process systems design and layout – gas dehydration;Full evaluation of operational and process conditions – H2S, CO2, O2 contents, pressures, temperatures, flow velocities and regimes, entrained solids, biological activity, etc.;Damage mechanism and failure modes with respect to health safety and environmental consequences; and,Materials availability and cost implications.Notwithstanding the use of carbon and low-alloy steels as sour service linepipe and its susceptibility to various types of cracking, the various materials treatment/processes such as heat treatment, cold working or both must be carefully controlled. Where cold working or rolling of the steel plate may occur, thermal stress relief must take place to mitigate any residual stresses that may remain within the steel. Similarly, where production fluids contains a sulphur or CO2 content which is too high for the corrosion-resistant properties of carbon steel alone, a corrosion-resistant alloy (CRA) is often employed.It provides a good balance between the mechanical properties of carbon steel and the corrosion resistant properties of a CRA. The use of CRAs such as Inconel 625 or 825 to form solid pipe is neither considered to be the norm nor can be economically justified owing to its prohibitive costs. Therefore, the synergistic combination of carbon steel and CRA together provides a cost-effective and optimum combination of materials.Such a combination of materials can be manufactured through metallurgical bonding, known as clad pipe (through co-extrusion, hot-rolled bonding, explosive bonding), or by only a mechanical bond between the CRA and steel (through thermohydraulic gripping), known as lined pipe.Mitigation at the manufacturing stageManufacturing of sour linepipe requires optimum steel chemistry and ‘steel cleanliness’. The presence of free sulphur during steel manufacture causes a reduction in overall steel mechanical properties, especially toughness; which dictates the requirements for very low sulphur concentrations; typically 0.005–0.010 per cent.The use of manganese as an alloying element (and having particular importance as a de-sulphuriser and de-oxidiser element) during steel manufacture provides a mechanism whereby any remaining sulphur can be removed to form manganese sulphide.The manganese sulphide inclusions formed have a significant influence on the mechanical properties of steel – such as toughness, hardness etc., with their size, composition and numbers influencing steel cleanliness – and must therefore be removed. Such inclusions are usually benign in low-strength steels, and their transverse ductile toughness is sufficient to prevent any ductile fracture. However, for the typical higher strength steels used for linepipe applications, higher transverse toughness values are required.As part of linepipe manufacture, steel plate is hot rolled, causing the inclusions to transform into an elongated morphology known as ‘stringers’, owing to their ductility. Often with sour service pipelines, the presence of atomic hydrogen can diffuse through the steel structure accumulating at the apex of stringers. Recombination of atomic into molecular hydrogen causes a pressure build-up at these stress concentrator sites, causing crack initiation and subsequent propagation over time. Characteristic cracking or ‘stepwise’ cracking where successive cracks are ‘joined’ are well documented in practice and in the literature.In addition, the type of rolling is important in order to produce steels which are grain refined, can achieve high strength and toughness in the heat-affected zone (HAZ), provide excellent weldability and formability and, importantly, high-resistance against cold cracking. This is achievable through a process known as thermomechanical rolling process (i.e. deformation without recrystallisation) and thermomechanical controlled process, which combines thermomechanical rolling with accelerated cooling.To ensure that the final steel product is free from detrimental ‘stringers’, the use of compounds such as calcium or cerium are typically employed, whereby its combination with sulphides is greater than with manganese and promotes a transformation of the elongated forms into spherical particles. In this way, any potential sites for hydrogen diffusion and potential steel cracking cannot now take place.Prior to fabrication of production linepipe, pre-qualification testing is a normal procedure that includes hardness testing in accordance with NACE specification (NACE MR0175), and is carried out to ensure that during production, welding of linepipe achieves a hardness value on materials testing of no greater than 22 HRC (Rockwell Hardness scale) in order to obviate brittle fracture within the weld itself, parent metal and HAZ. Similarly, the welding procedure must introduce strict controls for welding parameters, welding consumables as well as control and storage of welding rods.The hardness of parent materials and of welds and their HAZs play important roles in determining the sulphide stress cracking resistance of carbon and low-alloy steels. Hardness control can be an acceptable means of obtaining sulphide stress cracking resistance.Mitigation at the operational stageSo far examined have been a number of mitigation methods which provide certain controls in terms of safeguarding sour service pipelines. In addition, can also be introduced (additional measures) during the pipeline operational and maintenance stage in the form of a robust pipeline management system.Pipelines and chemicals management plays a critical role in all pipeline operations and more so with respect to sour service pipelines. Through the implementation of a well-planned risk-based inspection plan, a thorough internal and external examination of pipelines can be carried out and their condition assessed using methodologies such as remotely operated vehicles, divers, and intelligent pigging (in-line inspection). The collective data from the inspection and surveys provide a condition assessment of the internal and external pipeline condition, as well as providing a confidence statement as to the continued pipeline’s ‘fitness for purpose’ or otherwise to the pipeline operator.In this case therefore, pipeline management must be robust such that both physical and chemicals maintenance is applied to pipelines in sour service. Pro-active pipeline pigging – both intelligent and maintenance – will ensure that the pipeline is kept clean but also that the internal/external condition of the pipeline shall be known. Periodic pigging of pipelines removes liquids, solids, various debris, and other contaminants. In addition, pig ‘trash’ analysis is a useful way to understand what is being transported within the pipeline.Pipeline pigging is one of the most effective methods of not only cleaning the pipelines but also reducing the potential for any bacterial colonisation – such as sulfate-reducing bacteria (SRBs) – leading to microbiologically influenced corrosion attack, and under deposit corrosion effects, leading potentially to loss of pipeline containment or complete failure. It is important therefore that the selection, type and size of pigs is correctly made in order to ensure complete effectiveness and resulting cleanliness for the pipeline, as this plays an extremely important part in terms of improving the effectiveness of corrosion inhibitor and biocide treatments for sour pipelines in terms of chemical volumes and contact time.Inhibitor and biocide treatments provide a barrier between the corrosive elements and the pipe surface itself and, dependent on requirements, can be applied either by a batch or continuous programme. All corrosion inhibitors and biocides used for pipelines will be recommended in accordance with manufacturers’ recommendations and specifications, as well as undergoing trials and testing (laboratory and field) to ensure that the correct materials are used. In the case of sour pipelines, determining the correct inhibitors, biocides as well as dosage rates and application methodologies becomes a critical task.Corrosion monitoring plays an essential part in providing information as to the internal condition of the pipeline. The ongoing monitoring of acid gases such as H2S and CO2 should be periodically assessed, as changes in operating conditions over the lifetime of a pipeline will inevitably occur such as increasing water cuts, dissolved metals and entrained solids such as sand.Sour service pipelines under the influence of SRBs have been well studied and documented to date. The use of bio-spools in low- and high-pressure systems in conjunction with other corrosion monitoring methods as discussed, can be well placed to monitor such bacteria presence and yield extremely useful data on corrosion activity and efficacy of biocide treatments for corrosion control.ConclusionSour service pipelines carrying fluids or gases in addition to a wet internal environment causes problems to the pipeline leading to corrosion and potential loss of containment or complete breakdown of the pipeline. In addition, the presence of SRBs also play a critical role in generating hydrogen sulphide gas and equally cause potential pipeline corrosion problems.The article outlines a number of mitigation methods with respect to sour service gas pipelines, such as during manufacturing and fabrication stages and, importantly, during the pipelines operational and management phases. The use of well-planned and structured inspection, maintenance and repair regimes together with a robust campaign of pipelines and chemicals management will be well placed to mitigate the effects of pipeline deterioration and potential failure as a result of sour gas.Appeared in issue: Pipelines International — December 2011And if you dealing with a sour well make sure you explore the options from Duoline Technologies atwww.duoline.com http://pipelinesinternational.com/news/sour_gas_pipelines_how_do_we_deal_with_them/065073/

Pipeline Corrosion Prevention Suggestions From NACE

2011-12-16T06:42:00.000-08:00

White Papers : Pipeline CorrosionPublic Affairs – White Papers Pipeline Corrosion Unprotected pipelines, whether buried in the ground, exposed to the atmosphere, or submerged in water, are susceptible to corrosion. Without proper maintenance, every pipeline system will eventually deteriorate. Corrosion can weaken the structural integrity of a pipeline and make it an unsafe vehicle for transporting potentially hazardous materials. However, technology exists to extend pipeline structural life indefinitely if applied correctly and maintained consistently.How Do We Control Pipeline Corrosion?Four common methods used to control corrosion on pipelines are protective coatings and linings, cathodic protection, materials selection, and inhibitors.Coatings and linings are principal tools for defending against corrosion. They are often applied in conjunction with cathodic protection systems to provide the most cost-effective protection for pipelines.Cathodic protection (CP) is a technology, which uses direct electrical current to counteract the normal external corrosion of a metal pipeline. CP is used where all or part of a pipeline is buried underground or submerged in water. On new pipelines, CP can help prevent corrosion from starting; on existing pipelines; CP can help stop existing corrosion from getting worse.Materials selection refers to the selection and use of corrosion-resistant materials such as stainless steels, plastics, and special alloys to enhance the lifespan of a structure such as a pipeline. Materials selection personnel must consider the desired lifespan of the structure as well as the environment in which the structure will exist. Corrosion inhibitors are substances which, when added to a particular environment, decrease the rate of attack of that environment on a material such as metal or steel reinforced concrete.Corrosion inhibitors can extend the life of pipelines, prevent system shutdowns and failures, and avoid product contamination.Evaluating the environment in which a pipeline is or will be located is very important to corrosion control, no matter which method or combination of methods is used. Modifying the environment immediately surrounding a pipeline, such as reducing moisture or improving drainage, can be a simple and effective way to reduce the potential for corrosion.Furthermore, using persons trained in corrosion control is crucial to the success of any corrosion mitigation program. When pipeline operators assess risk, corrosion control must be an integral part of their evaluation.What is the Solution?Corrosion control is an ongoing, dynamic process. The keys to effective corrosion control of pipelines are quality design and installation of equipment, use of proper technologies, and ongoing maintenance and monitoring by trained professionals. An effective maintenance and monitoring program can be an operator's best insurance against preventable corrosion related problems.Effective corrosion control can extend the useful life of all pipelines. The increased risk of pipeline failure far outweighs the costs associated with installing, monitoring, and maintaining corrosion control systems. Preventing pipelines from deteriorating and failing will save money, preserve the environment, and protect public safety.http://www.nace.org/content.cfm?parentid=1046¤tID=1424

Instale o DUOLINE® 20 na tubulação

2011-12-09T07:53:00.001-08:00

Tubulações resistentes à corrosão voltadas ao campo de petróleo para a injeção de água marinha e eliminação da água salobra ou de outros fluidos corrosivos que degradam o meio ambiente. Desempenho comprovado historicamente na injeção de fluido e gás corrosivos para aplicações em alto mar e em base terrestre.Uma alternativa de custo-benefício para itens tubulares de aço de liga de alto valor utilizados na injeção de água marinha e eliminação da água salobra em operações de produção em alto mar.O DESAFIO:• O impacto dos altos custos, associados com itens tubulares especial- mente ligados para a injeção de água marinha e a eliminação de flui- dos e gases corrosivos, diminui os lucros de operação da plataforma e não contribui ao valor econômico do projeto.• O equipamento para a remoção de oxigênio e sólidos dissolvidos pos- sui implicações de área afetada em plataformas cheias e proporciona custos adicionais ao projeto.• Produtos com revestimento interno não são bem adequados a ambi- entes altamente corrosivos e o tempo entre as operações de inter- venção em poços é diminuído. O impacto disto é um gasto de fun- cionamento aumentado na plataforma sobre aquele que os clientes da DUOLINE® estão acostumados.• Regulamentações federais e estaduais e permissões custosas estão afe- tando a economia do processo na medida em que a eliminação de fundo de poço cada vez faz mais sentido.A SOLUÇÃO:Instale o DUOLINE® 20 na tubulação de aço ao carbono para a pro- teção interna contra corrosão. DUOLINE® 20 é um revestimento duráv- el de epóxi reforçada com vidro (GRE) que pode ser instalado em aços ao carbono para uma alternativa menos custosa e igualmente eficiente a ligas metálicas caras. DUOLINE® 20 pode ser instalado em tubulações ou armações finalizadas com conexões padrões ou premium.www.duoline.com

Great Article on Alloys for Offshore Applications

2011-12-02T07:17:00.001-08:00

Materials selections must be given detailed attention at every stage of the design, construction and operation of systems and equipment for application in offshore oil and gas production. Full attention must be given to general corrosion resistance, selective corrosion resistance (by pitting and crevice attack) and stress corrosion cracking susceptibility in sour hydrogen sulphide environments if failures, loss of production and costly maintenance are to be avoided. Even more important than these considerations is the need to maintain offshore safety. Thus the specification and use of materials which combine corrosion resistance with high mechanical strength is a fundamental requirement.A greater understanding of the offshore environment and more detailed knowledge of the conditions under which offshore structures and systems have to operate will obviously contribute to the selection of the correct materials.Corrosion in Sea Water and Offshore EnvironmentsSea water is highly corrosive and offshore installations are often exposed to temperature extremes. The corrosion resistance of a material is therefore equally as important as mechanical strength. The introduction of chlorine by adding hypochlorite solution to sea water to give biofouling resistance can reduce the corrosion resistance of certain stainless steels, particularly under crevice conditions. Hydrocarbon process systems often have to withstand the potentially corrosive effects of hydrogen sulphide and acid conditions associated with the dissolved carbon dioxide which is often present. Corrosion can weaken elements of an otherwise well designed ,structure or affect individual equipment components to such an extent that they cease to be serviceable. Unfortunately, the fight against corrosion itself can lead to equally damaging side effects such as the release of nascent hydrogen. This can be generated as a result of cathodic protection measures adopted to protect a structure or by dissimilar metal coupling. The presence of such hydrogen can given rise to hydrogen-induced cracking of steels and nickel base alloys.Alloys for Offshore ApplicationsMetals manufacturers have spent much time and effort in developing alloys specifically to meet offshore needs. The alloys developed have had to be suitable for shafts and bolting as wellas many other applications. These have included sea water and process pipework, water injection and booster pumps, line shaft pumps, emergency shutdown valves, anchorages and tensioners for riser protection systems, multiphase pumps and remotely operated vehicle components.The Development of MarinelOne particularly significant corrosion-resistant alloy (CRA) development led to the introduction of an ultra high strength cupronickel alloy (Marinel), approximately five years ago. This alloy was added to the range of alloys available for selection with reference to particular equipment where corrosion and hydrogen embrittlement could occur offshore. Most high strength iron and nickel based alloys and titanium alloys are prone to hydrogen embrittlement, the effect usually becoming more severe as the strength increases. Thus these alloys when operating in a high-stress condition will be more susceptible to hydrogen embrittlement than the same alloys operating under lower stress. Hydrogen embrittlement is of particular concern where high strength (usually B7 carbon steel, 720 N.mm-2 yield point) bolting is used on subsea structures. The operating stress level usually taken to represent a critical situation with respect to hydrogen embrittlement is that given by the yield stress of B7 carbon steel which has the value of 720 N.mm-2.Use of Cathodic ProtectionCathodic protection by sacrificial anodes or impressed current is extensively used to protect subsea structures from corrosion. This technique can generate hydrogen which, if absorbed, may lead to embrittlement of metallic components with the resultant danger of premature failure. The time-dependent nature of the ingress of hydrogen may mean that an apparently unaffected subsea critical component, for example a bolt, fails in an instant after it has performed satisfactorily for several years in service. Failure occurs when the residual ductile core is reduced in area by an encroaching hydrogen embrittlement front to a cross-section which cannot carry the load placed upon it. As an example, the failure of alloy K-500 riser clamp bolts has been reported in the April 1985 issue of Materials Performance (p37). Charging of UNS N 05500 (high strength 70Ni-3OCu alloy) with hydrogen has been shown to result in the hydrogen embrittlement of nonmagnetic drill collars. This has been thought to be due to galvanic coupling of the collars with carbon steel (see the October 1986 issue of Materials Performance, p28). It has also been suggested that a documented example of cracking in high strength steel legs of jack-up rigs was associated with hydrogen-induced stress corrosion cracking, the hydrogen being generated by the cathodic protection system operating in hydrogen sulphide contaminated seawater (February 1989 issue of Veritec Offshore Technology Journal).Transport of Hydrogen into a MetalThe entry of hydrogen into a metal can be purely diffusion-controlled, or can be assisted by dislocation transport and the latter effect has been experimentally demonstrated by the measurement of hydrogen permeation rates through nickel whilst it is undergoing plastic deformation (see volume 13, 1979 of Scripta Metallurgica, pp 927-932). Dislocation sweep-in of hydrogen from the surface in the case of several different metals has been found to be consistent with the calculated energy of activation of hydrogen-induced cracking (see pp 233-239 of the proceedings of the 1976 TMSAIME international conference on the effects of hydrogen on the behaviour of metals). During hydrogen transport, the hydrogen can be deposited at various ‘trap-sites’ or internal discontinuities such as grain boundaries or precipitates.Susceptibility to Hydrogen EmbrittlementThese can take the form of ‘reversible’ traps which the hydrogen can subsequently leave, or ‘irreversible’ traps, which the hydrogen cannot leave and which tend to encourage local fracture through a lowering of the surface energy of the material. The effectiveness of the traps in promoting hydrogen embrittlement is related to the degree of strengthening present in the material matrix, as it is well established that materials in a higher strength state (i.e. cold worked or age hardened) are more susceptible to hydrogen embrittlement than the same materials in a lower strength condition. Thus, measurement of both the hydrogen entry kinetics of a metal (or alloy) and the ability of the metal to trap hydrogen would give an indication of its hydrogen embrittlement susceptibility. Overall solubility of hydrogen does have an influence on hydrogen embrittlement characteristics, as iron, nickel and titanium have relatively high hydrogen solubilities (>1cc/cc) and these materials are more susceptible to hydrogen embrittlement than aluminium and copper alloys, whose solubilities are generally less than 0.1 cc/cc. The hydrogen diffusion coefficients of steel and titanium are greater than 10-6 cm2.s-1, whereas the hydrogen diffusion coefficients of nickel, aluminium and copper alloys are approximately 10-10 cm2.s-1, although this does not take into account dislocation transport or grain boundary diffusion.Nickel-Copper Alloys and Hydrogen EmbrittlementTwo alloys which are interesting to compare are the age hardening nickel-copper alloy K-500 and age hardening cupronickel Marinel, which have similar mechanical properties and hydrogen diffusion characteristics. In comparing the chemical composition of these two alloys, see Table 1, it is apparent that they contain almost the same basic elements, the major difference between them being the Cu:Ni ratio. In the case of Marinel the high Cu:Ni ratio renders the alloy immune to hydrogen embrittlement and this has been found to be largely due to the reduced ability of this alloy to trap the hydrogen irreversibly.Table 1. Typical composition of bolting.Marinel in Offshore ApplicationsIn offshore situations many developments have widely employed Marinel bolting for splash zone and subsea. Bolting subsea has been used with 13Cr steel, 22Cr duplex and 25Cr duplex steel manifold, valve and choke flanges. Subsea developments using the alloy include Lyell, Strathspey, Nelson, Heidrun, Johnston and Nelson.Good galling resistance obviates the need for a lubricant during assembly and nuts can be readily removed after a period of service if required.For the Conoco Lyell subsea manifold Marinel bolting was chosen for its greater mechanical strength and corrosion resistance compared with grade 660 steel. The bolts were bolt tensioned and assembled without lubricant. Stud bolts have been subjected to a laboratory examination after 18 months service (nearly 12 months with the manifold in operation) and apart from the expected calcareous deposit, appeared completely unaffected by service.Duplex Stainless Steels in Offshore ApplicationsA most significant contribution to the fight against corrosion offshore has been made by duplex stainless steels. These have often been adopted on offshore structures in preference to carbon steel or other stainless steels. The value of the duplex stainless steel is that it combines the basic toughness of the more common austenitic stainless steels with the higher strength and improved corrosion resistance of ferritic steels. The optimum chemical composition of these steels provides a high level of corrosion resistance in chloride media together with high mechanical strength and ductility. Other benefits include the ability of some duplex stainless steels to be used at quite low sub-zero temperatures and be able to resist stress corrosion cracking.A significant feature of duplex stainless steel is that its pitting and crevice corrosion resistance is greatly superior to that of standard austenitic alloys. Pitting resistance equivalent numbers (PREN), a standard industry measure, are often in the high 30s while the latest duplex alloys exceed a PREN of 40. This is an increasingly common specification for certain offshore duties. However, PREN numbers only provide an approximate grading of alloys and do not account for the microstructure of the material. An acceptance corrosion test on material in the supply condition is so much more meaningful.The Evolution of Duplex Stainless SteelsFerralium alloy 255 was the world’s first commercial 25% chromium duplex stainless steel when it was introduced over 20 years ago. It pioneered the use of a deliberate nitrogen addition in order to improve ductility and corrosion resistance. Further research has demonstrated the importance of using duplex stainless steels containing both nitrogen and copper.Super Duplex Stainless Steels for Offshore ApplicationsFor offshore and indeed, onshore applications, the availability of a super duplex (25% chromium) stainless steel alloy in a variety of forms is important. For example, bar, forgings, castings, sheet, plate, pipe/tube, welding consumables, flanges, fittings, dished ends and fasteners are available. In terms of other benefits, the high allowable design stress of this alloy type in comparison with other duplex stainless steels and austenitic stainless steels, including 6% Mo type, is significant. It also offers excellent castability, weldability and machinability. These features are complemented by excellent fatigue resistance and galvanic compatibility with other high alloy stainless steels.Twenty-two percent chromium stainless steels provide better pitting resistance and resistance to crevice corrosion than type 316 stainless steel by virtue of a more stable passive film and also have greater mechanical strength. However, for optimum corrosion resistance, a 25% chromium high alloy duplex stainless steel is required and these alloys are often referred to as super duplex stainless. Even within this category, it is important to select the correct grade of material to get versatility in handling a wide range of corrosive media and for confidence that the alloy will cope with any excursions or transient operating conditions which make the environment more aggressive.Materials Selection for Offshore ApplicationsOffshore structures themselves present different requirements of materials depending upon whether their application is topside, splash zone or subsea. Topside, duplex materials are suitable for a wide range of bolting applications and material such as Ferralium alloy 255 provide up to B7 steel strength, excellent corrosion resistance and a service life equal to the life of the system, thereby contributing to reduced maintenance costs. In the splash zone, the alloy has already demonstrated its suitability for sea water resistance with over 15 years service on North Sea installations and has been widely employed for riser bolting and components on riser protection system on TLPs.Emergence of New Super Duplex Stainless SteelsImproved materials in the super duplex stainless steel category continue to be developed by manufacturers offering better or differently combined characteristics, features and benefits. These alloys, generally with a PREN > 40, are produced to conform to a number of UNS designations which appear in ASTM product form specifications. Castings and wrought forms are available. Typical of recent developments is Ferralium alloy SD40 (conforming to UNS S 32550) with a PREN > 40.0 and providing a minimum 0.2% proof stress of 550N.mm-2 and a UTS of 760 N.mm-2. This 25% chromium super duplex material results from a carefully controlled composition and balanced austenitic/ferritic structure with a substantial content of molybdenum and nitrogen.For the complete article visit: http://www.azom.com/article.aspx?articleid=1732

Understanding Oil-Shale

2011-11-18T07:19:00.001-08:00

Many folks seem to not to understand the basics so we thought we would share this technical piece.Geology and Resources of Some World Oil-Shale DepositsReprint of: USGS Scientific Investigations Report 2005-5294By John R. DyniIntroductionOil shale is commonly defined as a fine-grained sedimentary rock containing organic matter that yields substantial amounts of oil and combustible gas upon destructive distillation. Most of the organic matter is insoluble in ordinary organic solvents; therefore, it must be decomposed by heating to release such materials. Underlying most definitions of oil shale is its potential for the economic recovery of energy, including shale oil and combustible gas, as well as a number of byproducts. A deposit of oil shale having economic potential is generally one that is at or near enough to the surface to be developed by open-pit or conventional underground mining or by in-situ methods.Oil shales range widely in organic content and oil yield. Commercial grades of oil shale, as determined by their yield of shale oil, ranges from about 100 to 200 liters per metric ton (l/t) of rock. The U.S. Geological Survey has used a lower limit of about 40 l/t for classification of Federal oil-shale lands. Others have suggested a limit as low as 25 l/t.Deposits of oil shale are in many parts of the world. These deposits, which range from Cambrian to Tertiary age, may occur as minor accumulations of little or no economic value or giant deposits that occupy thousands of square kilometers and reach thicknesses of 700 m or more. Oil shales were deposited in a variety of depositional environments, including fresh-water to highly saline lakes, epicontinental marine basins and subtidal shelves, and in limnic and coastal swamps, commonly in association with deposits of coal.In terms of mineral and elemental content, oil shale differs from coal in several distinct ways. Oil shales typically contain much larger amounts of inert mineral matter (60-90 percent) than coals, which have been defined as containing less than 40 percent mineral matter. The organic matter of oil shale, which is the source of liquid and gaseous hydrocarbons, typically has a higher hydrogen and lower oxygen content than that of lignite and bituminous coal.In general, the precursors of the organic matter in oil shale and coal also differ. Much of the organic matter in oil shale is of algal origin, but may also include remains of vascular land plants that more commonly compose much of the organic matter in coal. The origin of some of the organic matter in oil shale is obscure because of the lack of recognizable biologic structures that would help identify the precursor organisms. Such materials may be of bacterial origin or the product of bacterial degradation of algae or other organic matter.The mineral component of some oil shales is composed of carbonates including calcite, dolomite, and siderite, with lesser amounts of aluminosilicates. For other oil shales, the reverse is true-silicates including quartz, feldspar, and clay minerals are dominant and carbonates are a minor component. Many oil-shale deposits contain small, but ubiquitous, amounts of sulfides including pyrite and marcasite, indicating that the sediments probably accumulated in dysaerobic to anoxic waters that prevented the destruction of the organic matter by burrowing organisms and oxidation.Although shale oil in today's (2004) world market is not competitive with petroleum, natural gas, or coal, it is used in several countries that possess easily exploitable deposits of oil shale but lack other fossil fuel resources. Some oil-shale deposits contain minerals and metals that add byproduct value such as alum [KAl(SO4)2.12H2O], nahcolite (NaHCO3), dawsonite [NaAl(OH)2CO3], sulfur, ammonium sulfate, vanadium, zinc, copper, and uranium.The gross heating value of oil shales on a dry-weight basis ranges from about 500 to 4,000 kilocalories per kilogram (kcal/kg) of rock. The high-grade kukersite oil shale of Estonia, which fuels several electric power plants, has a heating value of about 2,000 to 2,200 kcal/kg. By comparison, the heating value of lignitic coal ranges from 3,500 to 4,600 kcal/kg on a dry, mineral-free basis (American Society for Testing Materials, 1966).Tectonic events and volcanism have altered some deposits. Structural deformation may impair the mining of an oil-shale deposit, whereas igneous intrusions may have thermally degraded the organic matter. Thermal alteration of this type may be restricted to a small part of the deposit, or it may be widespread making most of the deposit unfit for recovery of shale oil.The purpose of this report is to (1) discuss the geology and summarize the resources of selected deposits of oil shale in varied geologic settings from different parts of the world and (2) present new information on selected deposits developed since 1990 (Russell, 1990).Recoverable ResourcesThe commercial development of an oil-shale deposit depends upon many factors. The geologic setting and the physical and chemical characteristics of the resource are of primary importance. Roads, railroads, power lines, water, and available labor are among the factors to be considered in determining the viability of an oil-shale operation. Oil-shale lands that could be mined may be preempted by present land usage such as population centers, parks, and wildlife refuges. Development of new in-situ mining and processing technologies may allow an oil-shale operation in previously restricted areas without causing damage to the surface or posing problems of air and water pollution.The availability and price of petroleum ultimately effect the viability of a large-scale oil-shale industry. Today, few, if any deposits can be economically mined and processed for shale oil in competition with petroleum. Nevertheless, some countries with oil-shale resources, but lack petroleum reserves, find it expedient to operate an oil-shale industry. As supplies of petroleum diminish in future years and costs for petroleum increase, greater use of oil shale for the production of electric power, transportation fuels, petrochemicals, and other industrial products seems likely.Determining Grade of Oil ShaleThe grade of oil shale has been determined by many different methods with the results expressed in a variety of units. The heating value of the oil shale may be determined using a calorimeter. Values obtained by this method are reported in English or metric units, such as British thermal units (Btu) per pound of oil shale, calories per gram (cal/gm) of rock, kilocalories per kilogram (kcal/kg) of rock, megajoules per kilogram (MJ/kg) of rock, and other units. The heating value is useful for determining the quality of an oil shale that is burned directly in a power plant to produce electricity. Although the heating value of a given oil shale is a useful and fundamental property of the rock, it does not provide information on the amounts of shale oil or combustible gas that would be yielded by retorting (destructive distillation).The grade of oil shale can be determined by measuring the yield of oil of a shale sample in a laboratory retort. This is perhaps the most common type of analysis that is currently used to evaluate an oil-shale resource. The method commonly used in the United States is called the "modified Fischer assay," first developed in Germany, then adapted by the U.S. Bureau of Mines for analyzing oil shale of the Green River Formation in the western United States (Stanfield and Frost, 1949). The technique was subsequently standardized as the American Society for Testing and Materials Method D-3904-80 (1984). Some laboratories have further modified the Fischer assay method to better evaluate different types of oil shale and different methods of oil-shale processing.The standardized Fischer assay method consists of heating a 100-gram sample crushed to -8 mesh (2.38-mm mesh) screen in a small aluminum retort to 500ºC at a rate of 12ºC per minute and held at that temperature for 40 minutes. The distilled vapors of oil, gas, and water are passed through a condenser cooled with ice water into a graduated centrifuge tube. The oil and water are then separated by centrifuging. The quantities reported are the weight percentages of shale oil (and its specific gravity), water, shale residue, and "gas plus loss" by difference.The Fischer assay method does not determine the total available energy in an oil shale. When oil shale is retorted, the organic matter decomposes into oil, gas, and a residuum of carbon char remaining in the retorted shale. The amounts of individual gases-chiefly hydrocarbons, hydrogen, and carbon dioxide-are not normally determined but are reported collectively as "gas plus loss," which is the difference of 100 weight percent minus the sum of the weights of oil, water, and spent shale. Some oil shales may have a greater energy potential than that reported by the Fischer assay method depending on the components of the "gas plus loss."The Fischer assay method also does not necessarily indicate the maximum amount of oil that can be produced by a given oil shale. Other retorting methods, such as the Tosco II process, are known to yield in excess of 100 percent of the yield reported by Fischer assay. In fact, special methods of retorting, such as the Hytort process, can increase oil yields of some oil shales by as much as three to four times the yield obtained by the Fischer assay method (Schora and others, 1983; Dyni and others, 1990). At best, the Fischer assay method only approximates the energy potential of an oil-shale deposit.Newer techniques for evaluating oil-shale resources include the Rock-Eval and the "material-balance" Fischer assay methods. Both give more complete information about the grade of oil shale, but are not widely used. The modified Fischer assay, or close variations thereof, is still the major source of information for most deposits.It would be useful to develop a simple and reliable assay method for determining the energy potential of an oil shale that would include the total heat energy and the amounts of oil, water, combustible gases including hydrogen, and char in sample residue.Origin of Organic MatterOrganic matter in oil shale includes the remains of algae, spores, pollen, plant cuticle and corky fragments of herbaceous and woody plants, and other cellular remains of lacustrine, marine, and land plants. These materials are composed chiefly of carbon, hydrogen, oxygen, nitrogen, and sulfur. Some organic matter retains enough biological structures so that specific types can be identified as to genus and even species. In some oil shales, the organic matter is unstructured and is best described as amorphous (bituminite). The origin of this amorphous material is not well known, but it is likely a mixture of degraded algal or bacterial remains. Small amounts of plant resins and waxes also contribute to the organic matter. Fossil shell and bone fragments composed of phosphatic and carbonate minerals, although of organic origin, are excluded from the definition of organic matter used herein and are considered to be part of the mineral matrix of the oil shale.Most of the organic matter in oil shales is derived from various types of marine and lacustrine algae. It may also include varied admixtures of biologically higher forms of plant debris that depend on the depositional environment and geographic position. Bacterial remains can be volumetrically important in many oil shales, but they are difficult to identify.Most of the organic matter in oil shale is insoluble in ordinary organic solvents, whereas some is bitumen that is soluble in certain organic solvents. Solid hydrocarbons, including gilsonite, wurtzilite, grahamite, ozokerite, and albertite, are present as veins or pods in some oil shales. These hydrocarbons have somewhat varied chemical and physical characteristics, and several have been mined commercially.Thermal Maturity of Organic MatterThe thermal maturity of an oil shale refers to the degree to which the organic matter has been altered by geothermal heating. If the oil shale is heated to a high enough temperature, as may be the case if the oil shale were deeply buried, the organic matter may thermally decompose to form oil and gas. Under such circumstances, oil shales can be source rocks for petroleum and natural gas. The Green River oil shale, for example, is presumed to be the source of the oil in the Red Wash field in northeastern Utah. On the other hand, oil-shale deposits that have economic potential for their shale-oil and gas yields are geothermally immature and have not been subjected to excessive heating. Such deposits are generally close enough to the surface to be mined by open-pit, underground mining, or by in-situ methods.The degree of thermal maturity of an oil shale can be determined in the laboratory by several methods. One technique is to observe the changes in color of the organic matter in samples collected from varied depths in a borehole. Assuming that the organic matter is subjected to geothermal heating as a function of depth, the colors of certain types of organic matter change from lighter to darker colors. These color differences can be noted by a petrographer and measured using photometric techniques.Geothermal maturity of organic matter in oil shale is also determined by the reflectance of vitrinite (a common constituent of coal derived from vascular land plants), if present in the rock. Vitrinite reflectance is commonly used by petroleum explorationists to determine the degree of geothermal alteration of petroleum source rocks in a sedimentary basin. A scale of vitrinite reflectances has been developed that indicates when the organic matter in a sedimentary rock has reached temperatures high enough to generate oil and gas. However, this method can pose a problem with respect to oil shale, because the reflectance of vitrinite may be depressed by the presence of lipid-rich organic matter.Vitrinite may be difficult to recognize in oil shale because it resembles other organic material of algal origin and may not have the same reflectance response as vitrinite, thereby leading to erroneous conclusions. For this reason, it may be necessary to measure vitrinite reflectance from laterally equivalent vitrinite-bearing rocks that lack the algal material.In areas where the rocks have been subjected to complex folding and faulting or have been intruded by igneous rocks, the geothermal maturity of the oil shale should be evaluated for proper determination of the economic potential of the deposit.Classification of Oil Shale

Oil shale has received many different names over the years, such as cannel coal, boghead coal, alum shale, stellarite, albertite, kerosene shale, bituminite, gas coal, algal coal, wollongite, schistes bitumineux, torbanite, and kukersite. Some of these names are still used for certain types of oil shale. Recently, however, attempts have been made to systematically classify the many different types of oil shale on the basis of the depositional environment of the deposit, the petrographic character of the organic matter, and the precursor organisms from which the organic matter was derived.A useful classification of oil shales was developed by A.C. Hutton (1987, 1988, 1991), who pioneered the use of blue/ultraviolet fluorescent microscopy in the study of oil-shale deposits of Australia. Adapting petrographic terms from coal terminology, Hutton developed a classification of oil shale based primarily on the origin of the organic matter. His classification has proved to be useful for correlating different kinds of organic matter in oil shale with the chemistry of the hydrocarbons derived from oil shale.Hutton (1991) visualized oil shale as one of three broad groups of organic-rich sedimentary rocks: (1) humic coal and carbonaceous shale, (2) bitumen-impregnated rock, and (3) oil shale. He then divided oil shale into three groups based upon their environments of deposition - terrestrial, lacustrine, and marine.Terrestrial oil shales include those composed of lipid-rich organic matter such as resin spores, waxy cuticles, and corky tissue of roots, and stems of vascular terrestrial plants commonly found in coal-forming swamps and bogs. Lacustrine oil shales include lipid-rich organic matter derived from algae that lived in freshwater, brackish, or saline lakes. Marine oil shales are composed of lipid-rich organic matter derived from marine algae, acritarchs (unicellular organisms of questionable origin), and marine dinoflagellates.Several quantitatively important petrographic components of the organic matter in oil shale-telalginite, lamalginite, and bituminite-are adapted from coal petrography. Telalginite is organic matter derived from large colonial or thick-walled unicellular algae, typified by genera such as Botryococcus. Lamalginite includes thin-walled colonial or unicellular algae that occurs as laminae with little or no recognizable biologic structures. Telalginite and lamalginite fluoresce brightly in shades of yellow under blue/ultraviolet light.Bituminite, on the other hand, is largely amorphous, lacks recognizable biologic structures, and weakly fluoresces under blue light. It commonly occurs as an organic groundmass with fine-grained mineral matter. The material has not been fully characterized with respect to its composition or origin, but it is commonly an important component of marine oil shales. Coaly materials including vitrinite and inertinite are rare to abundant components of oil shale; both are derived from humic matter of land plants and have moderate and high reflectance, respectively, under the microscope.Within his three-fold grouping of oil shales (terrestrial, lacustrine, and marine), Hutton (1991) recognized six specific oil-shale types: cannel coal, lamosite, marinite, torbanite, tasmanite, and kukersite. The most abundant and largest deposits are marinites and lamosites.Cannel coal is brown to black oil shale composed of resins, spores, waxes, and cutinaceous and corky materials derived from terrestrial vascular plants together with varied amounts of vitrinite and inertinite. Cannel coals originate in oxygen-deficient ponds or shallow lakes in peat-forming swamps and bogs (Stach and others, 1975, p. 236-237).Lamosite is pale- and grayish-brown and dark gray to black oil shale in which the chief organic constituent is lamalginite derived from lacustrine planktonic algae. Other minor components in lamosite include vitrinite, inertinite, telalginite, and bitumen. The Green River oil-shale deposits in western United States and a number of the Tertiary lacustrine deposits in eastern Queensland, Australia, are lamosites.Marinite is a gray to dark gray to black oil shale of marine origin in which the chief organic components are lamalginite and bituminite derived chiefly from marine phytoplankton. Marinite may also contain small amounts of bitumen, telalginite, and vitrinite. Marinites are deposited typically in epeiric seas such as on broad shallow marine shelves or inland seas where wave action is restricted and currents are minimal. The Devonian-Mississippian oil shales of eastern United States are typical marinites. Such deposits are generally widespread covering hundreds to thousands of square kilometers, but they are relatively thin, often less than about 100 m.Torbanite, tasmanite, and kukersite are related to specific kinds of algae from which the organic matter was derived; the names are based on local geographic features. Torbanite, named after Torbane Hill in Scotland, is a black oil shale whose organic matter is composed mainly of telalginite derived largely from lipid-rich Botryococcus and related algal forms found in fresh- to brackish-water lakes. It also contains small amounts of vitrinite and inertinite. The deposits are commonly small, but can be extremely high grade. Tasmanite, named from oil-shale deposits in Tasmania, is a brown to black oil shale. The organic matter consists of telalginite derived chiefly from unicellular tasmanitid algae of marine origin and lesser amounts of vitrinite, lamalginite, and inertinite. Kukersite, which takes its name from Kukruse Manor near the town of Kohtla-Järve, Estonia, is a light brown marine oil shale. Its principal organic component is telalginite derived from the green alga, Gloeocapsomorpha prisca. The Estonian oil-shale deposit in northern Estonia along the southern coast of the Gulf of Finland and its eastern extension into Russia, the Leningrad deposit, are kukersites.Evaluation of Oil-Shale ResourcesRelatively little is known about many of the world's deposits of oil shale and much exploratory drilling and analytical work need to be done. Early attempts to determine the total size of world oil-shale resources were based on few facts, and estimating the grade and quantity of many of these resources were speculative, at best. The situation today has not greatly improved, although much information has been published in the past decade or so, notably for deposits in Australia, Canada, Estonia, Israel, and the United States.Evaluation of world oil-shale resources is especially difficult because of the wide variety of analytical units that are reported. The grade of a deposit is variously expressed in U.S. or Imperial gallons of shale oil per short ton (gpt) of rock, liters of shale oil per metric ton (l/t) of rock, barrels, short or metric tons of shale oil, kilocalories per kilogram (kcal/kg) of oil shale, or gigajoules (GJ) per unit weight of oil shale. To bring some uniformity into this assessment, oil-shale resources in this report are given in both metric tons of shale oil and in equivalent U.S. barrels of shale oil, and the grade of oil shale, where known, is expressed in liters of shale oil per metric ton (l/t) of rock. If the size of the resource is expressed only in volumetric units (barrels, liters, cubic meters, and so on), the density of the shale oil must be known or estimated to convert these values to metric tons. Most oil shales produce shale oil that ranges in density from about 0.85 to 0.97 by the modified Fischer assay method. In cases where the density of the shale oil is unknown, a value of 0.910 is assumed for estimating resources.Byproducts may add considerable value to some oil-shale deposits. Uranium, vanadium, zinc, alumina, phosphate, sodium carbonate minerals, ammonium sulfate, and sulfur are some of the potential byproducts. The spent shale after retorting is used to manufacture cement, notably in Germany and China. The heat energy obtained by the combustion of the organic matter in oil shale can be used in the cement-making process. Other products that can be made from oil shale include specialty carbon fibers, adsorbent carbons, carbon black, bricks, construction and decorative blocks, soil additives, fertilizers, rock wool insulating material, and glass. Most of these uses are still small or in experimental stages, but the economic potential is large.This appraisal of world oil-shale resources is far from complete. Many deposits are not reviewed because data or publications are unavailable. Resource data for deeply buried deposits, such as a large part of the Devonian oil-shale deposits in eastern United States, are omitted, because they are not likely to be developed in the foreseeable future. Thus, the total resource numbers reported herein should be regarded as conservative estimates. This review focuses on the larger deposits of oil shale that are being mined or have the best potential for development because of their size and grade.http://geology.com/usgs/oil-shale/

DUOLINE ® VISÃO GERAL DAS OPÇÕES DE CONEXÃO

2011-11-11T07:03:00.001-08:00

DUOLINE ® pode ser instalado em artigos tubulares roscados do campo de petróleo com praticamente qualquer opção de conexão. Há poucos princípios básicos gerais a respeito da conexão e de dispositivos de proteção de conexão para o DUOLINE ®.As conexões roscadas de API geralmente empregam o anel de barreira de corrosão DUOLINE ® (CBR), que possui mais de 50 anos de história em uso. Uma opção para a tubulação roscada API é o novo dispositivo de conexão sem anel, testado em campo, que foi desenvolvido para facilitar a instalação.As conexões premium empregam um CBR PTFE em forma de “T” com o sistema de DL-Ring ou com a variação “FGL” para roscas premium comuns.VISÃO GERAL DAS OPÇÕES DE CONEXÃOTubulação ou armações roscadas API comAnel de barreira de corrosão e DUOLINE 20• Utilizada extensivamente em aplicações de injeção desde 1971• Foi utilizada em tamanhos de tubo de 2-1/16" até 7"• EUE LT&C, ST&CVAM®• Acomoda roscas e acoplamentos não modificados sem problemas• Qualificado através de programas de teste 95% VME de 4 quadrantes completos• Foi utilizada em diâmetros de tubo de 3-1/2" até 10-3/4"VISÃO GERAL DAS OPÇÕES DE CONEXÃO (CONTINUAÇÃO)Benoit-BTS-FGL• Uma variação de rosca de tubulação de “2 etapas” I J da família de roscas Benoit• Foi utilizada em tamanhos de tubo de 2-1/16" até 4-1/2"Nippon Steel NSCT-FGL e variaçõesNSCC-FGL da família de roscas Nippon• Usada em poços exigentes de produção e injeção profundos em alto mar e em terra firme.• Foi utilizada em tamanhos de tubo de 3-1/2" até 7"Armações de reforço com anel de barreira de corrosão e Duolione® 20• Foi utilizada em tamanhos de tubo de 4-1/2" até 9-5/8"• Utilizada em aplicações onde as conexões API padrão não bastam e as conexões de altas propriedades não são viáveis• Acomoda roscas e acoplamentos não modificados sem problemasISO 9001:2008PARA MAIORES DETALHES SOBRE NOSSA EMPRESAE NOSSOS PRODUTOS, ACESSE www.duoline.com250 Bluebird LaneGilmer, TX 756449019 North County Road WestOdessa, TX 79764Web-site: www.duoline.comRua Vis Condede Sepatiba 935/1211Centro - Niteroi - RJ - BrazilWeb-site: www.fiberware.com.br

Corrosion Management Summit In Oil and Gas

2011-11-04T07:20:00.000-07:00

Corrosion Management Summit In Oil and GasCorrosion is an unfortunate given in the oil and gas industry. If that corrosion goes undetected, the results can be disastrous, and very costly. Only with proper attention to safeguards, maintenance and modern protective technologies can help the world's oil supplies remain steady, and the environment safe from disaster. The total annual cost of corrosion in the oil and gas production industry is estimated to be $1.372 billion, broken down into $589 million in surface pipeline and facility costs, $463 million annually in downhole tubing expenses, and another $320 million in capital expenditures related to corrosion.Fleming Gulf's “Corrosion Management Summit in Oil and Gas 2012” will address the key issues and prevention strategies in corrosion in the Oil and Gas industry as well the technology implemented to deal with the assets to corrosion control.The presence of carbon dioxide (CO2), hydrogen sulphide (H2S) and free water can cause severe corrosion problems in oil and gas pipelines. One of the biggest shortcomings in the field of corrosion management is the lack of skilled personnel. Protecting the integrity of oil and gas assets depends both on effective corrosion engineering, and corrosion management. The industry needs skilled engineers understand the industry, the chemistry of corrosion and the technologies required to address it.Corrosion management is part of an overall system, which develops, implements, reviews, and maintains both policy and strategy for managing, mitigating and preventing corrosion. While it may not be possible to completely eliminate any instance of corrosion and the leakage that results, proper attention, maintenance and technology will keep it to a manageable level.Key Speakers and Advisors: Dr Paul Rostron, Departments of Chemistry / Chemical Engineering, The Petroleum Institute, Abu Dhabi Mohamed Daoud, Project Quality Manager, ADCO Hanafi Ali, Senior Materials, Corrosion and Inspection Engineer, Shell, Malaysia Rufat Azizov, Material and Corrosion Engineer, BP, Azerbaijan Tarek Awad, Oil and Gas Expert, Egypt Abdel Aziz M. Salah El Din, Regional Manager Europe and Africa, Hudson Technology and Strategic Studies Nitin Jayaprakash , Corrosion and Materials Engineer, Tebodin and Partner LLC, OmanKey Topics: Role of Corrosion Inhibitors in the Oil and Gas Industry Cost of Corrosion - Where are the prices headed and Why? Cathodic Protection in Oil and Gas pipelines– Managing Cathodically protected structures Corrosion under Insulation – A Perennial Problem in the Oil and Gas Industry Material Selection Philosophy – The approach for material selection Corrosion Monitoring Techniques – Recent developments, Applicability and LimitationsWho should attend:Project Engineer, Mechanical engineer, Technical Directors, Inspection engineer, Integration specialist/engineer/Manager, Head of engineering, Pipeline engineers, CEO/MD/VP/Exec Directors/Chief Executives, Senior Planner, Corrosion engineer/Manager, Research, Regional Manager, Materials Manager, Marketing Manager, Maintenance Manager/Directors, Quality Head/Director/Manager, Operations Manager/engineer, Team leader, Asset Integrity manager/engineer, Field engineer, Department manager, Safety engineer, Production/Process Head/Director/Manager , Risk manager, Laboratory SpecialistIf you are interested in sharing your industry knowledge as a speaker or panelist, please contact :Jason Mendonca, T: +971 4609 1570 , F: + 971 4609 1589, E: jason.mendonca@fleminggulf.comhttp://www.fleminggulf.com/oil-and-gas/middle-east/corrosion-management-summit-in-oil-and-gas

Duoline 20 Fiberglass Liner

2011-10-28T08:24:00.000-07:00

- Premium Connections( 250°F working temperature) HOW DOES DUOLINE®20 WORK? DUOLINE® 20, manufactured by DUOLINE® Technologies, is a filament-wound Glass-Reinforced Epoxy (GRE) fiberglass liner which is installed to OCTG in corrosive service. It is widely accepted that GRE lining is a more robust alternative to internal plastic coating. DUOLINE®20 is a very effective corrosion barrier with a long history of tubular protection in a variety of offshore and landbased applications. Proven performance leader in corrosive (gas/fluid) injection and disposal for offshore and land-based applications. Where Will You Benefit From Using DUOLINE® 20? 250°F working temp CO2/Water injection/Disposal Chemical disposal Gas Production API or Premium Thread Compatibility Why Use DUOLINE® 20? 35 year proven field history Lower cost alternative to CRA Durable/Long lasting corrosion protection Most complete corrosion package on the market Most abrasive resistant lining system available http://www.duoline.com/ContentGather.cfm?navid=2&sublinkid=68

North Sea Rig Utilization Soars Above Global Average

2011-10-28T08:07:00.000-07:00

North Sea offshore drilling activities are faring much better than worldwide operations. Total average utilization for region's mobile offshore drilling fleet is 92 percent, which compares quite favorably to the global average of 83 percent. The harsh corrosive environment along with a higher degree of regulatory oversight (especially in Norwegian waters) relative to the rest of the globe contributes to a limited participation by offshore drillers.

Dividing the region up into two parts (Norway in the North and the United Kingdom/Netherlands in the South) provides a clearer picture on average dayrates. In the southern section the going rate for a jackup is in the low-$120 k/day range. Conversely, jackup rigs to the north are averaging in the low-$310s. Both locales compare favorably to the worldwide jackup average, which is in the low-$100s.A similar disparity due to capabilities and harsh environment demands exists for floaters as well. A floater operating in the southern waters of the North Sea commands an average dayrate in the low-$300s, while floaters to the north average in the high-$430s. We would note that the majority of the rigs servicing operators in the North Sea are suited for mid-water duties (i.e. less than 4000'). The global mid-water floater average is in the mid-$290s.http://www.rigzone.com/news/article.asp?a_id=112102

China-made drilling rig to be in Cuba by end 2011

2011-10-26T06:13:00.000-07:00

World Oil News Center

China-made drilling rig to be in Cuba by end of 2011

HAVANA -- A Chinese-made oil rig is on schedule to arrive off Cuba and begin drilling before the end of 2011, a spokesman for Spanish oil company Repsol YPF said.

Spokesman Kristian Rix would neither confirm nor deny recent reports of delays as the Scarabeo-9 rig travels to the Caribbean island, but he said the project has always been based on a window of time and things are still on schedule.

China-made drilling rig to be in Cuba by end 2011

Duoline Technologies Unidades Expandidas Novas Capacidades

2011-10-21T05:34:00.000-07:00

TECNOLOGIAS TESTADAS AO LONGO DO TEMPO PARA PROTEGER AS TUBULAÇÕES DOS CAMPOS DE PETRÓLEO CONTRA A CORROSÃONOVAS UNIDADES• Nova fábrica ultramoderna, com 130.000 pés quadrados, agora aberta e em funcionamento.• Localizada em Gilmer, Texas, a apenas quatro horas do principal porto de transportes de Houston, Texas; a cinco horas de Nova Orleans, Louisiana.NOVAS CAPACIDADES• Sistemas de fabricação com reforço de fibra de vidro (FRP) altamente eficiente e exclusivo, suportado por controles de processo avançados.• Automatizado para fornecer repetitividade e precisão.• Gama completa de rastreabilidade.• Incorpora tecnologias revisadas, testadas e comprovadas para uma ótima produtividade.• Pontos de controle de qualidade incorporados no processo de produção.• Certificados ISO 9001:2008TECNOLOGIAS TESTADAS AO LONGO DO TEMPO PARA PROTEGER AS TUBULAÇÕES DE CAMPOS DE PETRÓLEO CONTRA A CORROSÃO• Desde 1964, mais de 80 milhões de pés de tubulação revestida com epóxi reforçada com vidro da Duoline® foram instalados com sucesso em todo o mundo.• Além de sua nova unidade, a Duoline® Technologies continuará a operar em todas as fábricas e instalações de serviço atuais em Odessa, Texas.Está na hora de você começar a obter os benefícios da valiosa tecnologia da Duoline na luta contra a corrosãoO sistema premium de revestimento interno resistente à corrosão da Duoline® para tubulações de aço para gás e petróleo é uma solução de alto desempenho, valiosa e de custo-benefício para super- ar o alto custo da corrosão.O processo de inserção do revestimento exclusivo da Duoline® cria uma barreira comprovada con- tra corrosão dentro da tubulação de aço. O benefício? Isolamento dos fluidos e gases corrosivos do campo de petróleo em relação ao aço. O custo de substituição da tubulação defeituosa de pro- dução de fundo de poço ou linhas de fluxo submarinas é extremamente alto. A Duoline® oferece um desempenho inigualável na prevenção da corrosão em condições muito exigentes. O sistemada Duoline® oferece desempenho superior e maior vida útil se comparado a opções menos duráveis de revestimentos por spray. Os sistemas da Duoline® também são internacionalmente considerados uma alternativa de custo-benefício para aços de alta-liga.Se a sua aplicação se encaixar em qualquer uma das seguintes categorias, você tem um motivo para entrar em contato conosco!• POÇOS DE PRODUÇÃO DE GÁS E ÓLEO • PLATAFORMAS EM ALTO MAR • OPERAÇÕES DE INTERVENÇÃO EM POÇOS EM TERRA FIRME • POÇOS DE EXTRAÇÃO PELA INJEÇÃO DE ÁGUA • POÇOS DE EXTRAÇÃO PELA INJEÇÃO DE CO2• SISTEMAS DE ELIMINAÇÃO DE ÁGUA MARINHA • POÇOS DE ELIMINAÇÃO DE QUÍMICA • SERVIÇO DE GÁS AMARGOPARA MAIORES DETALHES SOBRE NOSSA EMPRESAE NOSSOS PRODUTOS, ACESSE www.duoline.comDuoline Technologies250 W Bluebird LaneGilmer, TX 756459019 North County Road WestOdessa, TX 79764Web-site: www.duoline.comEmail: information@duoline.comLupatech FiberwareRua Vis Condede Sepatiba 935/1211Centro - Niteroi - RJ - BrazilWeb-site: www.fiberware.com.brTel: 903.734.1371Fax: 903.734.1571Tel: 432.552.9700Fax: 432.552.9701Tel: + 55 21 2620 0145Fax: + 55 21 2620 1005Email: Getulio.Goulart@lupatech.com.br

Haynesville leads the herd in shale gas production

2011-10-12T05:01:00.000-07:00

Want to learn a lot about Haynesville---this is the article for you---From World Oil---DAVID MICHAEL COHEN, Managing EditorThere is no question that sustained low prices for natural gas have taken their toll on the Haynesville shale play of northwestern Louisiana and East Texas. The number of rigs working in the Haynesville has fallen steadily during the past 15 months, and there are reasons to be concerned that activity could continue falling off. Producers have largely completed the drilling needed to hold onto their expensive leases in the play, and two attractive, liquids-rich shale targets elsewhere in Louisiana have been attracting recent attention: the Tuscaloosa marine shale in the middle of the state and the Brown Dense or Lower Smackover shale to the north. Judging from the rapid pace of development in South Texas’ liquids-rich Eagle Ford shale, these two new prospects could soon be seriously competing for rigs with the dry-gas Haynesville.However, Haynesville drilling in East Texas has stayed relatively stable during the last year in the face of the Eagle Ford boom, unlike its North Texas neighbor, the Barnett. Despite its extreme depth and high-pressure, high-temperature (HPHT) operating conditions, resulting in well costs often exceeding $9 million, the Haynesville’s very high initial production (IP) rates and estimated ultimate recoveries (EURs) have kept some of the biggest players very active there. Furthermore, many operators are testing the highly prospective overlying Bossier shale, which could add production to keep Haynesville wells profitable even if gas prices continue to stagnate around $4/Mcf. Another good sign relates to Australian mining giant BHP Billiton’s purchase this summer of heavily Haynesville-invested independent Petrohawk for $15.1 billion in cash. In September, Petrohawk submitted drilling applications for 18 wells in Swan Lake field overlapping Caddo and Bossier Parishes and five wells in Caspiana field of Bossier Parish, in the gas-factory configurations that have become customary in the play.After less than three years of development, Haynesville production surpassed that of the Barnett in March, making it the highest-producing US shale play at slightly more than 5 Bcfd, according to an analysis by the US Energy Information Administration (EIA) based on data from market analysts Bentek Energy. Compare that performance with more than nine years that it took the Barnett to reach the 5-Bcfd mark. In the long term, indications are for Haynesville production to soar even higher, with a number of companies investigating projects to make use of the gas.In May, Cheniere Energy won US Department of Energy approval to export liquefied natural gas at its Sabine Pass LNG terminal in Louisiana, which could liquefy up to 2.2 Bcfd of gas. Terminals in Lake Charles, Louisiana, and Freeport, Texas, are seeking similar approval. Additionally, Encana is developing LNG and compressed natural gas infrastructure in Louisiana that could be the vanguard of a new market for Haynesville gas. The company opened its first CNG fueling station in Red River Parish last November, and in April it struck a deal to supply fuel for 200 new LNG trucks belonging to Heckmann Water Resources, a California company that provides water-hauling services to Haynesville producers. Along similar lines, Chesapeake has agreed to invest $150 million toward the construction of 250–300 LNG truck fueling stations as part of a $1 billion plan to increase long-term US gas demand.Even if persistent low gas prices compared with oil complicate the economics of CNG or LNG, increased Haynesville gas production could find a market through conversion to pricier liquid fuels. In September, South African energy and chemicals group Sasol announced an 18-month feasibility study for an $8–10 billion gas-to-liquids plant to be built near Lake Charles, Louisiana. The facility would be the first of its kind in the US and would produce either 2 million tonnes per annum (mtpa) or 4 mtpa of diesel fuel and related products from up to 840 MMcfd of feed gas. Construction could start as early as 2013, with completion by 2018.GEOLOGY AND RESOURCESUnderlain by the Smackover limestone formation and overlain by sandstones of the Cotton Valley group, the Upper Jurassic-aged Haynesville shale takes up an area of about 9,000 sq mi primarily in Louisiana and stretching into East Texas and southern Arkansas. With net thickness ranging 200–300 ft, the Haynesville is encountered at depths of 10,500–13,500 ft (top) and is being developed with horizontal wells that typically have laterals of 4,000–5,000 ft, for a measured depth range of about 16,000–19,000 ft. Completions typically have 10–15 fracture stages per lateral, with slickwater treatments that contain 300,000–400,000 lbm of proppant pumped at up to 80 bbl/min.Being the deepest unconventional play in development, the Haynesville is subject to HPHT conditions not generally seen in other shales. According to David Breeden, lab manager at Newpark Drilling Fluids, bottomhole temperatures are generally 350°F and higher, with the coolest sections in the shallower Texas part of the play being about 325°F. In Red River Parish, Louisiana, BHTs up to 400°F have been encountered. Bottomhole pressures exceeding 12,000 psi have been reported, and treatment pressures approach 15,000 psi. According to a paper presented at last year’s SPE Annual Technical Conference and Exhibition by authors from Hexion Specialty Chemicals (now Momentive), closure stresses in the Haynesville range 9,000–12,000 psi, compared with 6,000 psi or less in the Fayetteville and up to 9,500 psi in the Bakken. Closure stress is the stress required to hold a fracture open.Bossier potential. E&P companies active in the Haynesville have begun directing some capital toward the Bossier shale, which overlies much of the Haynesville. Originally a name used for the Texas part of the Haynesville, the Bossier has come to denote a separate shale formation directly overlying the Haynesville on both sides of the Texas-Louisiana border. It is also known as the Middle or Lower Bossier. (The Upper Bossier shale, composed mostly of sands, lies farther southwest.)According to Robert Hutchinson, an oil and gas investor focused on the Haynesville, very few rigs have been directed exclusively at the Bossier. “Because the Bossier is above the Haynesville, there is very little Bossier drilling activity since a successful Haynesville well holds the Bossier by production,” Hutchinson told World Oil. “While some operators have drilled exploratory Bossier wells to estimate reserves, there are few Bossier wells drilled for the sake of production.” Nonetheless, several active Haynesville operators have touted their Bossier results within investor presentations, eager to show the added value this new shale interval brings to their Haynesville assets.New resource assessment. In August, the EIA released a new appraisal of technically recoverable shale gas and oil resources across the undeveloped portions of 20 US shale plays. The study estimates that there was 750 Tcf of technically recoverable shale gas in the US as of Jan. 1, 2009, of which 10% (74.7 Tcf) was in the Haynesville. The agency noted, however, that these estimates could be way off, since many of the plays are in early stages of development and production from future wells might vary widely from that of existing wells. This is particularly true in the Haynesville, which was only discovered in 2007 and has seen production increase much more rapidly than other shale plays.The assessment further stated that, in the 3,547 sq mi of Haynesville shale that has been developed, the average EUR per well was 3.57 Bcf, higher than in any other area studied except for the Cana field portion of the Woodford, in western Oklahoma, which saw EURs averaging 5.20 Bcf. EURs in the top 10% of Haynesville wells average 13 Bcf, followed by 9.75 Bcf/well for the next 20%, 6.50 Bcf/well for the next 30%, and 3.25 Bcf/well for the bottom 40%.Geophysical properties. Recently, CGGVeritas has applied its integrated geophysical workflow, based on amplitude-vs.-offset (AVO) analyses of pre-stack azimuthal seismic data calibrated with well logs and core measurements, to its Tri-Parish multiclient library in the Haynesville shale. The company’s approach seeks to characterize shale gas reservoirs by providing a quantitative understanding of rock properties such as acoustic impedance, Poisson’s ratio and Young’s modulus—which are related to reservoir properties such as porosity, total organic content (TOC) and mineral content. The goal is to predict optimal drilling and completion locations, in order to increase productivity and reduce exploration risk. According to company literature, “Relative production estimates across the field can be derived by combining seismic estimates of lithological, geomechanical and stress properties, correlated to existing well measurements. The selection of geomechanical and lithological parameters that provide the best correlation with production will vary from one shale play to another and must be derived for each survey using multi-attribute correlation.”CGGVeritas says the overall regional stress regime in the Haynesville has an east-west maximum horizontal stress orientation, and there are observable lateral variations in the local stresses. Zones with relatively high brittleness (derived from estimated properties such as isotropic Young’s modulus and lambda-mu-rho) have been identified, and their associated differential horizontal stress ratio (DHSR, important for predicting hydraulic fracture behavior), fracture initiation pressure and closure stress have been estimated.Multi-attribute analysis of the Tri-Parish data suggests that better development locations have a combination of certain key rock properties, such as high porosity, siliceous mineral content and TOC. Detailed rock property analyses showed that properties such as Poisson’s ratio and lambda-rho (incompressibility) are useful for identifying such areas. Areas of low Poisson’s ratio indicate the more siliceous, low-carbonate content normally associated with better porosity development. Bulk volume of gas can be estimated by combining these properties via multi-attribute analysis. These seismically derived predictions were calibrated with existing production, well core and well test measurements to determine optimal zones for drilling and completion. In general, no single attribute was found to provide sufficient information to correlate seismic data to production. However multiple elastic- and stress-related attributes (Fig. 1) were used to predict observed production (compensated by horizontal well length) with 95% correlation, showing several undrilled areas with potentially high productivity.Fig. 1. CGGVeritas’ multi-attribute analysis within its Tri-Parish multiclient library in the Haynesville: Dynamic Young’s modulus (red represents high values) with plates showing DHSR and maximum horizontal stress orientation and bubbles showing initial production.Fig. 1. CGGVeritas’ multi-attribute analysis within its Tri-Parish multiclient library in the Haynesville: Dynamic Young’s modulus (red represents high values) with plates showing DHSR and maximum horizontal stress orientation and bubbles showing initial production.OPERATOR ACTIVITYThe number of rigs working in the Haynesville and Bossier shales reached a peak of 184 in July 2010, according to Hutchinson. The current rig count, as compiled on Hutchinson’s blog haynesvilleplay.com, is over 40% down from that high level, at a Sept. 26 count of 106 rigs, Fig. 2. Of that total, 76 are working in the Louisiana part of the play and 30 across the Texas border, maintaining a split that has remained relatively steady since Hutchinson began reporting the count in January 2010.

Fig. 2. The Haynesville shale rig count has fallen over 40% from its peak in July 2010.Many large and small operators are active in the Haynesville; this report highlights the activities of just a few of the most active players. The rig counts used for each company are from haynesvilleplay.com, Table 1.Chesapeake. Oklahoma City-based shale gas pioneer Chesapeake drilled what is widely considered the Haynesville discovery well in 2007 (Dallas, Texas-based independent Cubic Energy also claims to have first drilled into the shale), following geoscientific investigation in 2005 and 2006. In 2008, Chesapeake formed a joint venture agreement with Houston-based Plains Exploration & Production, to which it sold 20% of its Haynesville and Bossier assets for about $3.2 billion in cash and drilling carries.Since its first Haynesville well, Chesapeake has built up its production in the play to an average of 1.085 Bcfd net (1.7 Bcfd gross) in July. “That’s been built 100% organically in just four years,” said CEO Aubrey McClendon in a second-quarter conference call. “If Chesapeake’s Haynesville asset were a stand-alone company, it would remarkably be the seventh largest gas producer in the US by itself.” Chesapeake’s Haynesville production in July represented more than one-third of the company’s total output, and included 15 MMcfd from the Bossier formation. The company holds 495,000 net Haynesville acres, about one-third of which (190,000 net acres) is overlain by the Bossier. Chesapeake’s net Haynesville acreage contains 4.157 Tcfe of proved reserves. The company’s drilling program is constrained by a relatively wide 650-acre spacing, and involves laterals of about 4,500 ft.For a long time the play’s top driller by far, Chesapeake cut its drilling activity in the Haynesville substantially during the third quarter, and now is just slightly ahead of runner-up Exco Resources with 20 rigs running in late September. That’s down from an average of about 35 active Haynesville/Bossier rigs in the first half, which were needed to hold by production the acreage. The company plans to continue cutting down to 15 Haynesville/Bossier rigs by end of year, and to hold at that level until gas prices go up. “That will have an effect on our production next year,” said Chief Operating Officer Steve Dixon in the conference call.Exco Resources. Unlike Chesapeake, Exco Resources has kept a relatively stable number of Haynesville/Bossier rigs running throughout 2011, so that the Dallas-based independent is now running neck-and-neck with Chesapeake at 19 rigs. Though down from the first half, that’s still higher than the 16.8 rigs that Exco average in 2010. The company holds 76,000 net acres with Haynesville/Bossier shale potential, primarily located in DeSoto and Caddo Parishes in Louisiana and in Harrison, Panola, Shelby, San Augustine and Nacogdoches Counties in Texas. A substantial portion of the acreage is held by existing Haynesville, Cotton Valley, Hosston and Travis Peak production.Exco’s active rigs are split between its Holly core development area in DeSoto Parish, Louisiana, and the Shelby trough area on the Texas side. In the core area, Exco has moved from delineation to full manufacturing mode, using multiwell pad development in an 80-acre spacing—tightened from the company’s previous 160-acre spacing in the area. In the Shelby area, the focus is on delineating the company’s position and holding acreage. Shelby is expected to transition to full manufacturing mode in 2012.The company completed 47 gross wells (20.4 net) in the Haynesville/Bossier play during the second quarter, and plans to drill a total of about 163 operated horizontal wells this year. That would be a 37% increase from the 119 Haynesville wells spudded by Exco during 2010, primarily in core DeSoto Parish area. The company’s Haynesville wells typically have laterals of 4,000–5,000 ft.Continuous improvement in drilling time and optimization of frac design have helped Exco keep its costs relatively flat. This effort has focused on the company’s northern Louisiana assets, where well costs have fallen from a high of $10.8 million in second-quarter 2010 to $9.35 million in second-quarter 2011, due to variables including bit selection, construction efficiencies, reducing nonproductive time, proppant type/volumes, horsepower, equipment rentals and perforation spacing. The company’s fastest well to date was drilled in 28 days. On 11 wells, the curve and entire lateral were drilled in a single bit run, and, in one well, Exco drilled from surface through the intermediate section with one bit run.Exco had 706.8 Bcfe of proved reserves in the Haynesville shale as of Dec. 31, 2010, largely due to strong delineation results in the Shelby area. IP rates in the area have averaged 18 MMcfd, with two Haynesville wells having IP rates over 30 MMcfd and one Bossier well over 25 MMcfd. In the Highlander segment of the Shelby area, average IP rates exceed 28 MMcfd.In August, Exco reported operated Haynesville/Bossier production of 1.2 Bcfd gross (365 MMcfd net), with 232 operated and 123 non-operated wells producing. The company estimated that an average of about 25–30 MMcfd net was curtailed due to plant shutdowns after an incident at its 50%-owned TGGT Holdings treating facility in Red River Parish killed one worker and injured another. Production was expected to remain curtailed through the end of the third quarter.In May 2010, Exco and BG Group jointly bought Common Resources, consisting of properties in Shelby, San Augustine and Nacogdoches Counties, Texas, for $442.1 million ($221.0 million net to Exco). Two months later, the two companies jointly purchased additional properties from Southwestern Energy for $357.8 million ($178.9 million net to Exco).Encana. Canadian gas producer Encana has seen strong growth in the Haynesville, where production was up 70% to 487 MMcfed in second-quarter 2011 from a 2010 average of 287 MMcfed, partially offsetting production decreases due to divestitures elsewhere in US. In 2009, the company averaged just 61 MMcfed from the Haynesville.Encana is shifting its drilling focus from lease retention to expanding and optimizing its pad drilling (or “hub”) activities, a transition that includes seeking regulatory approvals for longer laterals and building on its low-cost completion program. On the company’s drilling hubs, drilling times have been reduced 20% in the last year to 40 days, and a number of wells this year have been drilled in 35 days. In the first quarter of 2011, the shift to hub activity resulted in about a 25% reduction in drilling costs compared with lease-retention drilling. Further cost reductions are expected through the deployment this year of fit-for-purpose pumping equipment and service supply agreements.Drilling is down somewhat from last year, with 45 wells drilled in first-half 2011 and a planned total of 85 wells by year-end, vs. 106 net wells drilled in 2010. The company is operating 12 rigs in the Haynesville, down by almost half from a 2010 average of 22.4 rigs running. This demonstrates Encana’s increased drilling efficiency: In 2010 it drilled an average of 4.7 wells per rig running, compared with a projected 6.4 wells per rig in 2011 (if the first-half well counts and rig averages were applied to the whole year).During second-quarter 2011, Encana obtained regulatory approval for its first cross-unit, alternate-unit wells in Louisiana. The approval allows the company to drill horizontal wells with laterals of 7,500 ft across existing blocks of three sections. Encana plans to spud its first cross-unit well before the end of the year.ExxonMobil/XTO. In its 2010 annual report, ExxonMobil called the Haynesville and Bossier shales its “fastest growing unconventional play.” Exxon’s 240,000 net acres are operated by XTO, which the major acquired in mid-2010. That leasehold includes 67,000 net acres added last year, 46,000 acres of which came through the $695 million cash purchase of Boulder, Colorado-based Ellora Energy last October (along with production and pipeline capacity). The remaining 21,000 net acres were added through a 108,000-gross-acre joint venture with Encana. Exxon has been busy consolidating these Haynesville acquisitions into XTO, along with recently acquired Eagle Ford and Marcellus acreage.A relatively active drilling program throughout 2010 resulted in gross operated production of 250 MMcfd by the year’s end, more than four times that of year-end 2009. The company ran an average of 11.7 rigs in 2010, with development focused in its prolific southern core area. Bossier shale testing also began last year. XTO’s Haynesville/Bossier rig count has dipped somewhat this year, averaging 10.8 in the first half and falling to seven in late September.In a speech on June 14, XTO President Jack Williams said Exxon is applying its Fast-Drill technology in the Haynesville. According to company literature, “This physics-based process combines real-time digital analysis of the drilling system’s energy consumption with a structured approach to well planning and design to ensure that a well is drilled as efficiently and quickly as possible. Applying this method has resulted in a rate-of-penetration improvement of up to 100 percent.” Among other applications, the method helped Exxon to achieve record ROPs on extended-reach wells in the Sakhalin-1 project in Russia.El Paso. As El Paso Corp. prepares to spin off its E&P business into a publicly traded company called EP Energy by the end of the year, successful Haynesville drilling has been a major driver of the company’s overall production increases. As of June 30, El Paso had 83 operated wells and 260 MMcfed of total production related to its Haynesville program—more than one-third of the company’s total US production. The company currently has five rigs running in the play, and plans to keep about that many running through the rest of the year. The company estimates that it has 415 future drilling locations on its 43,000 net acres in the Haynesville, with resource potential of 800 Bcfe. It spent $197 million there in first-half 2011, 27% of its total capex budget and second only to the Eagle Ford.Of El Paso’s four major E&P operational areas, the Haynesville is the only one that is gas focused. This reflects the company’s confidence in the economics of the play even at low gas prices, especially in the busy Holly area of DeSoto Parish, Louisiana, where El Paso has about half of its Haynesville acreage and is one of several companies employing a gas-factory concept using multiwell pads. El Paso estimates that wells in the Holly area will cost $8.7–9.3 million to drill and complete, and will yield an EUR of 6–7 Bcfe, resulting in an internal rate of return between 20% and 30% at $4/MMBtu. By way of comparison, the company estimates wells in its other two Haynesville areas, Bethany Longstreet and Logansport, to have rates of return between 5% and 15%.Petrohawk. BHP Billiton’s $12.1 billion purchase of Petrohawk, closed in August, would seem to reflect at least in part a high level of confidence in the long-term profitability of Haynesville gas. After all, Petrohawk holds the second largest net leasehold in the play, after Chesapeake, at 368,000 acres—294,000 in Louisiana and 74,000 acres in Texas. It is also one of the top producers, averaging 684 MMcfed in the second quarter of this year.During the same time period, Petrohawk drilled 21 operated Haynesville wells, as well as 67 non-operated Haynesville wells and three Bossier wells. Non-operated activity exceeded expectations, in terms of both activity level and capex, primarily due to the transition to full section development by some industry partners.The company has achieved cost reductions in Haynesville completions of about $600,000–800,000 per well, largely as a result of changes in well design that require two fewer frac stages per well, lower overall sand requirements per well, and improved pricing for resin-coated sand. During the second quarter Petrohawk averaged slightly less than 45 days spud to spud, a reduction of five days compared with the preceding quarter. Significant additional improvements are expected as the company moves toward pad drilling and full section development toward the end of 2012. Meanwhile, the company substantially drew down its Haynesville rig fleet in the third quarter, to a late September count of four rigs, compared with averages of 12.5 in the first half and 14.2 in 2010.Improvements in water handling and usage have contributed to more flexibility in water sourcing. About half of all Petrohawk-operated wells in the play have been completed with 20% recycled water. In the first half of 2011, the company pumped over 47,000 bbl of recycled wastewater on Haynesville completions.Others. Shell, through its 100% owned subsidiary Shell Western Exploration and Production (SWEPI) is the owner of a 50% interest in leases that cover about 400,000 Haynesville acres in DeSoto, Red River, Sabine and Natchitoches parishes, the company told World Oil. Otherwise, the major has been exceptionally tight-lipped about its Haynesville assets, declining to comment on production, reserves or drilling activity. The company has kept a steady average of about nine rigs running in the play throughout 2010 and 2011.EOG Resources has directed 20% of its 2011 capex toward dry gas drilling to hold acreage, with a substantial portion of that drilling in the Haynesville/Bossier play. The Houston-based independent holds a 190,000-net-acre position in the play, containing 11 Tcf of potential (i.e., not proved) reserves—5.6 Tcf in the Haynesville shale and 5.4 Tcf in the Bossier. The company currently has six rigs operating in the play, down from an average of 7.2 in the first half and 10.4 in 2010.TECHNOLOGY ADVANCESMost of the technologies developed specifically for Haynesville have emerged in response to the extreme HPHT conditions of the formation in comparison with other producing shales. An instructive example of this is Newpark Drilling Fluids’ Evolution water-based drilling fluid system, developed in 2009 as an alternative to the oil-based muds (OBMs) that had become the default in the play. A number of operators had attempted different water-based muds (WBMs) in the Haynesville in order to reduce the high costs of drilling in the play (oil-based muds are more expensive, and more difficult to dispose of after use), but these attempts had failed.After considerable sampling and analysis of the shale, Newpark determined that the shale was not particularly reactive, as had previously been hypothesized. Rather, the major issues were the high temperature and carbon dioxide content. At the high temperatures found in the Haynesville, the standard viscosifying polymer of choice, xanthum gum, deteriorates rapidly.“We also discovered a significant amount of CO2 in with the gas, such that if you use a conventional bentonite mud, it flocculates severely, giving you a viscosity hump that significantly limits your lubricity,” lab manager David Breeden told World Oil. “The only way to treat out the CO2 is with lime, and at bottomhole temperatures of 350° and above, you don’t want very much lime because you’ll make cement. … So you’re constantly going over the two viscosity humps of CO2 and calcium.” The high mud weights required in the Haynesville, exceeding 15 lb/gal, further complicated the search for alternatives.Newpark went to work to formulate a water-based polymer system that exhibited thermal stability at temperatures in excess of 400°F, provided contaminant resistance to CO2 and drilled solids, and provided lubricity comparable to that of OBMs. The resulting system, incorporating a polymeric viscosifier and suspension agent, an HPHT lubricant, a rheology modifier and a general-purpose fluid conditioner, performed successfully in the field and became the first water-based system used repeatedly in the Haynesville.Just as the Haynesville’s high temperatures have caused problems for conventional muds, its high pressures have caused problems for conventional proppants, i.e., uncoated sand. At the formation’s high closure stresses, these proppants tend to crush and form large quantities of fines, which clog pore throats and limit productivity. As a result, stronger, resin-coated sand proppants have been increasingly popular in the Haynesville, with several suppliers struggling to keep up with the high demand.While most Haynesville-related technology advances have been related to getting gas out of the HPHT formation, the most important advances going forward will likely be those that present new ways of marketing the produced gas. Thus, planned investments in LNG export, LNG- and CNG-fueled vehicles and gas-to-liquids technologies may be the most hopeful sign yet for the play. http://www.worldoil.com/October-2011-Haynesville-leads-the-herd-in-shale-gas-production.html

Norway: Statoil’s First Fast-Track Project Visund South Moves Ahead

2011-10-07T07:09:00.000-07:00

Statoil’s first fast-track –project – Visund South – is moving ahead as planned. The seabed template has commenced its journey out to the field located south of Gullfaks in the North Sea.“We submitted the plan for development and operation of Visund South in January. Now, four months later, we’ve built the first seabed template for the first fast-track project. We’ve come a long way towards cutting the time from discovery to production in half,” says Kjetel Digre, who is responsible for project implementation in Technology, Projects & Drilling.The Visund South seabed template was placed on a barge at Grenland Group’s yard in Tønsberg last week. It will be installed on the field between the Gullfaks C and Visund platforms in June.Visund South is expected to come on stream in 2012.The template is the first to have been built from a standard catalogue for subsea equipment.This will form the basis for the continuing development and use of the standard catalogue in the fast-track portfolio.“We’ve been working closely with the supplier industry to develop standard equipment for this part of our field development portfolio. This means that we can start to build equipment more quickly and develop smaller finds more efficiently,” says Halfdan Knudsen, who heads up the fast-track portfolio on the NCS.It has taken less than a year to build the Visund South structure from the signing of the contract for subsea equipment with FMC.Subsea 7 will carry out the actual installation on the seabed.Visund South field installation will take place at the same time as that on the Marulk development, which Statoil is carrying out on behalf of operator Eni. This will mean increased efficiency and cost savings for both projects.Statoil’s high health, safety and environment (HSE) standards are fully integrated at all fast-track project development stages.“HSE integration at all fast-track development stages is crucial to our success. I believe that all of our efforts to standardise and industrialise field developments through the fast-track process will bring us a predictability that will impact safety in a positive way,” says Digre.http://subseaworldnews.com/2011/05/27/norway-statoil%E2%80%99s-first-fast-track-project-visund-south-moves-ahead/

More About Duoline

2011-10-04T10:50:00.000-07:00

Duoline Technologies, a member company of the Robroy Industries Group, found its beginnings in the oilfield industry designing, installing and operating produced saltwater gathering & disposal systems since 1953. Through these endeavors, Duoline Technologies developed the DUOLINE lining process in 1964 as a means to solve our own downhole steel tubular corrosion problems. Since that time we have installed more than 75 million feet of DUOLINE tubing worldwide. DUOLINE's unmatched http://www.blogger.com/img/blank.gifperformance has made it the most successful system for prevention of downhole tubular corrosion.

Headquartered in Odessa, Texas, Duoline Technologies have combined forces with three international partners who each will provide DUOLINE products and services for their respective territories. MaxTube Ltd. , with a DUOLINE lining facility base in Scotland and U.A.E. provide Duoline service to the North Sea, Europe, and the Middle East. Duoline Technologies and PanMarine Equipamentos e Servicos Ltda, in Rio de Janeiro, Brazil jointly operate a DUOLINE lining facility in the state of Sergipe, Brazil, near Aracaju. Rice Engineering & Operations LTD. operate a Duoline lining facility in Edmonton, Alberta, Canada.

Learn more:
www.duoline.com

Duoline® Fiberglass Lining Capabilities Now Available From New Facility In East Texas

2011-09-30T10:35:00.000-07:00

Duoline® Fiberglass Lining Capabilities Now Available From New Facility In East Texas

Gilmer, TEXAS --- Duoline® Technologies, an industry leader in solving oilfield corrosion problems through innovative products and services, announces the availability of their fiberglass linining capabilities from new facility in East Texas. DUOLINE-20 a premium internal corrosion lining system for petroleum industry applications was verified for optimum service life in Sweet and Sour Wells for 20 years.

New Lining Capabilities Include:

1-Fiberglass Lining capabilities of sizes ranging from 2 3/8" to 10 ¾"

2-Capability of lining standard EUE API Connections and Premium Connections (VAM TOP, Tenaris, Hunting, Hydril, JFE, and many more)

3-Lining of un-modified threads

4-Maximum lining length of 44' pipe

5-Quick Turnaround

6-Minimize freight cost (by half)

7-Servicing Louisiana, East Texas, Gulf of Mexico, Oklahoma, and surrounding vicinities

8-Engineering Technical Support

9-On-site liner manufacturing

10-Field Service Support

About Duoline®
Since 1964, more than 100 million feet of Duoline® glass reinforced epoxy linehttp://www.blogger.com/img/blank.gifd tubing have been successfully installed worldwide. Duoline® is a high performance, high-value, cost-effective solution to beating the high cost of corrosion.

The Duoline® system offers superior performance and longer service life compared to the less durable option of spray-on coatings. Duoline® systems are also internationally regarded as a cost effective alternative to high alloy steels.

For additional details about Duoline® products, contact: Oscar Zapata, Duoline® Technologies, 250 W Bluebird Rd.,Gilmer, Texas 75645-7234. Phone: 903.734.1371 | Fax: 903.734.1571. E-Mail:ozapata@duoline.com

Or visit: www.duoline.com

Tubulações resistentes à corrosão voltadas ao campo de petróleo

2011-09-23T07:34:00.000-07:00

DUOLINE® 20

Tubulações resistentes à corrosão voltadas ao campo de petróleo para a injeção de água marinha e eliminação da água salobra ou de outros fluidos corrosivos que degradam o meio ambiente. Desempenho comprovado historicamente na injeção de fluido e gás corrosivos para aplicações em alto mar e em base terrestre.

Uma alternativa de custo-benefício para itens tubulares de aço de liga de alto valor utilizados na injeção de água marinha e eliminação da água salobra em operações de produção em alto mar.

O DESAFIO:

• O impacto dos altos custos, associados com itens tubulares especial- mente ligados para a injeção de água marinha e a eliminação de flui- dos e gases corrosivos, diminui os lucros de operação da plataforma e não contribui ao valor econômico do projeto.

• O equipamento para a remoção de oxigênio e sólidos dissolvidos pos- sui implicações de área afetada em plataformas cheias e proporciona custos adicionais ao projeto.

• Produtos com revestimento interno não são bem adequados a ambi- entes altamente corrosivos e o tempo entre as operações de inter- venção em poços é diminuído. O impacto disto é um gasto de fun- cionamento aumentado na plataforma sobre aquele que os clientes da DUOLINE® estão acostumados.
http://www.blogger.com/img/blank.gif
• Regulamentações federais e estaduais e permissões custosas estão afe- tando a economia do processo na medida em que a eliminação de fundo de poço cada vez faz mais sentido.

A SOLUÇÃO:

Instale o DUOLINE® 20 na tubulação de aço ao carbono para a pro- teção interna contra corrosão. DUOLINE® 20 é um revestimento duráv- el de epóxi reforçada com vidro (GRE) que pode ser instalado em aços ao carbono para uma alternativa menos custosa e igualmente eficiente a ligas metálicas caras. DUOLINE® 20 pode ser instalado em tubulações ou armações finalizadas com conexões padrões ou premium.

http://www.duoline.com/

DEGRADATION OF OIL TRUNKLINE STEEL CAUSED BY INTERNAL CORROSION

2011-09-16T07:35:00.000-07:00

DEGRADATION OF OIL TRUNKLINE STEEL CAUSED BY
INTERNAL CORROSION
H. M. NYKYFORCHYN
Department of Corrosion-Hydrogen Degradation and Materials Protection, Karpenko Physico-Mechanical Institute of the
National Academy of Sciences of Ukraine
ABSTRACT
It is generally recognized that the corrosion-induced failure of oil trunklines is caused by corrosion damage of external surfaces of the pipes. However nowadays more attention is paid to the problem of the pipe internal corrosion. In this paper the problem of deterioration of the anticorrosion, mechanical and corrosion-mechanichfal properties of the low alloy 0.10C-Mn-Si steel after 28 years
of service is considered. The problem results from the water, which comes with the transported oil and settles at the bottom part of the pipe. Three areas of the steels were investigated: the original state (specimens were cut from as-manufactured pipe), the upper area and the lower area having
been in contact with the water. The following properties were evaluated for these areas: corrosion rate in residual water; impact strength; sensitivity to stress corrosion cracking in residual water at the moderate cathodic polarization determined by low rate loading of cylindrical specimens. It was
found that the material of the lower pipe area has the highest corrosion rate in water.
http://www.icf11.com/proceeding/EXTENDED/3464.pdf

MIT simulation accurately reconstructs pipe fractures

2011-09-13T07:44:00.000-07:00

MIT simulation accurately reconstructs pipe fractures

By Jennifer Chu, MIT

A computer model that tests automobile components for crashworthiness could also be of use to the oil and gas industry, according to researchers at MIT’s Impact and Crashworthiness Laboratory, who are now using their simulations of material deformation in car crashes to predict how pipes may fracture in offshore drilling accidents.

MIT researchers found a near-perfect match between their pipeline fracture simulation (bottom) and an image of the Deepwater Horizon's ruptured pipeline taken by an underwater robot. [Image: Tomasz Wierzbicki, Impact and Crashworthiness Laboratory]

As a case study, the team simulated the forces involved in the 2010 Deepwater Horizon explosion in the Gulf of Mexico, finding that their model accurately predicted the location and propagation of cracks in the oil rig’s drill riser – the portion of pipe connecting the surface drilling platform to the seafloor. In a side-by-side comparison, the researchers found that their model’s reconstruction closely resembled an image of the actual fractured pipe taken by a remotely operated vehicle shortly after the accident occurred. The group presented their results at the International Offshore and Polar Engineering Conference in June.

Tomasz Wierzbicki, professor of applied mechanics at MIT, says such a simulation could help oil and gas companies identify stronger or more flexible pipe materials that could help minimize the impact of a future large-scale accident.

“We are looking at what would happen during a severe accident, and we’re trying to determine what should be the material that would not fail under those conditions,” Wierzbicki says. “For that, you need technology to predict the limits of a material’s behavior.”

Wierzbicki has already laid much of the foundation for what he calls Fracture Predictive Technology through his work in car-crash safety testing. Over the years, he’s fine-tuned a testing method that combines physical experiments with computer simulations to predict the strength and behavior of materials under severe impacts.

For example, to safety-test materials used in automobile bodies, Wierzbicki first cuts small samples from a candidate such as steel, using a high-pressure water jet. He then sprays the sample with a fine pattern of speckles, covering the surface with tiny dots. After the spray dries, Wierzbicki clamps the cutout into a machine, which subjects specimens to different types of loading. A motion-capture camera, set up in front of the sample, takes images as it crumples, sending the images to a computer, which plots the image’s dots along a grid to show exactly when and where deformations occur.

By testing different shapes and sizes of materials under various pressures, Wierzbicki can determine a material’s overall mechanical properties, such as its strength and ductility. Knowing this, he says, it’s possible to create a simulation to predict a material’s behavior in any configuration, under any conditions. Determining the exact limits for materials is especially important for offshore drilling, he says, where pipes are continually subjected to tremendous pressures at great depths.

Wierzbicki and graduate students Kirki Kofiani and Evangelos Koutsolelos used the same principles to predict the strength and breaking points of the Deepwater Horizon’s drill riser.

Since the researchers were unable to obtain a sample from the actual collapsed riser, they consulted an offshore-drilling handbook, finding that the riser was likely made from X70, a grade of steel commonly used in such risers. The material’s mechanical properties closely matched those of TRIP 690, a grade of steel the team had previously tested in the lab.

The researchers drew up a computer model of the drill riser – a large-diameter pipe attached at one end to a large rectangle, representing the surface drilling platform. The team then ran a simulation that partially reconstructed the Deepwater Horizon accident: After methane gas erupted and shot to the surface, setting the entire platform on fire, the oil rig began to list and sink. The researchers simulated the sinking by slowly angling the rectangular platform downward.

As a result, the attached drill riser began to bend. A color-coded simulation showed points along the pipe where it was likely to crack: Green and blue meant the material was intact; yellow and red indicated it was at its breaking point. The group found four red areas where cracks – and oil leaks – were especially likely to occur.

The group had one point of comparison: an image, taken by an underwater robot shortly after the accident, of the ruined pipe. When the researchers compared their model with the real-life image, they found an almost perfect match.

Wierzbicki sees the results as an encouraging first step in applying the model to materials for offshore drilling.

Jorgen Amdahl, a professor in the Department of Marine Technology at the Norwegian University of Science and Technology, says the model’s main advantage is its ability to predict a pipe’s response under many different scenarios, from normal operations to severe accidents.

“It takes into account all ranges of stress states,” Amdahl says. “The approach will be very useful for the oil and gas industry with respect to assessment of pipe behavior under accidental stresses,” he says, such as severe deformations from capsizing, explosions, fires, and earthquakes.

While it’s unlikely that any pipe material could have remained intact during the Deepwater Horizon disaster, Wierzbicki says there are many improvements that can be made to shore up existing oil and gas pipelines. He and his group, whose research is partly sponsored by Royal Dutch Shell, will be analyzing samples from retired offshore pipes in the next few months.

“The deeper you go in the ocean, two or three miles down, the stronger material you need to withstand the pressure,” Wierzbicki says. “But stronger materials are more brittle and break more easily. So there’s a difficult problem for the offshore industry, and I think they can learn a lot from us.”

Published September 2011
http://www.desighttp://www.blogger.com/img/blank.gifnfax.net/enews/20110913/feature3.php

Sweet Oil

2011-09-09T10:48:00.000-07:00

Sweet crude oil is a type of petroleum. Petroleum is considered "sweet" if it contains less than 0.5% sulfur,[1] compared to a higher level of sulfur in sourhttp://www.blogger.com/img/blank.gif crude oil. Sweet crude oil contains small amounts of hydrogen sulfide and carbon dioxide. High quality, low sulfur crude oil is commonly used for processing into gasoline and is in high demand, particularly in the industrialized nations. "Light sweet crude oil" is the most sought-after version of crude oil as it contains a disproportionately large amount of these fractions that are used to process gasoline (naphtha), kerosene, and high-quality diesel (gas oil). The term "sweet" originated because the low level of sulfur provides the oil with a mildly sweet taste and pleasant smell. Nineteenth century prospectors would taste and smell small quantities of the oil to determine its quality
http://en.wikipedia.org/wiki/Sweet_crude_oil

DUOLINE-20 - A premium internal corrosion lining system for petroleum industry applications was verified for optimum service life in: Sweet wells for 20 years
To learn more visit:http://www.duoline.com/product.cfm

Corrosion and Prevention Oil and Gas Exploration and Production

2011-09-02T06:38:00.000-07:00

OIL AND GAS EXPLORATION AND PRODUCTION
GREGORY R. RUSCHAU, PH.D.1 AND MOHAMMED A. AL-ANEZI2
SUMMARY AND ANALYSIS OF RESULTS
Corrosion and Prevention
Domestic oil and gas production can be considered a “dinosaur industry” in the United States because most of
the significant onshore oil and gas reserves have been exploited. The significant recoverable reserves left to be
discovered and produced in the United States are probably limited to less convenient locations, such as deepwater
offshore, remote arctic locations, and difficult-to-manage reservoirs with unconsolidated sands. Materials and
corrosion control technologies used in traditional onshore production facilities have not significantly changed since
the 1970s. The materials and corrosion control technologies required for the more difficult production areas must be
more reliable due to the excessive cost of replacement or failure in these locations. Of course, the commodity price
of oil will continue to dictate whether or not these new developments will evehttp://www.blogger.com/img/blank.gifn be considered.
Downhole tubing, surface pipelines, pressure vessels, and storage tanks in oil and gas production are subject to
internal corrosion by water, which is enhanced by the presence of CO2 and H2S in the gas phase. Internal corrosion
control is the major cost item. The total annual cost of corrosion in the oil and gas production industry is estimated
to be $1.372 billion, broken down into $589 million in surface pipeline and facility costs, $463 million annually in
downhole tubing expenses, and another $320 million in capital expenditures related to corrosion.
For the full piece visit:
http://www.corrosioncost.com/pdf/oilgas.pdf

Corrosion-erosion monitor set for subsea

2011-08-26T08:26:00.000-07:00

What are your thoughts about this product?

Corrosion-erosion monitor set for subsea

Non-invasiveness, good repeatability and high coverage are listed among the key subsea selling points for ClampOn's new subsea corrosion-erosion monitor (CEM), the prototype of which will be on display for the first time at Houston's OTC show next month.

Previously installed topside, the CEM technology is considered ready for deployment subsea. The prototype has been tested subsea and field testing is scheduled this month.

The technology is based on dispersion of ultrasonic guided wave modes. By using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. ‘It is installed on the outer pipe wall to produce realtime wall thickness information, not as a spot measurement, but as a unique average path wall thickness,' explains ClampOn.

The CEM utilizes acoustic guided lamb waves (AGLW), a technology that gives an average wall thickness reading for larger pipe sections. The transducers are fixed at pre-determined spots on the pipe to monitor the wall thickness loss in larger stretches of the pipe, typically up to 2m. The absence of any transducer movement or mechanical motion adds a high degree of robustness to the instrument. As it is permanently installed and needs no recalibration, ClampOn believes the CEM will be both more cost effective and reliable than other ROV-controlled methods.

Various system configurations are possible, ranging from stand-alone monitoring stations with data logging to full real-time integration into existing data infrastructure. Subsea installation avenues already identified by the developers include a retrofitted ROV solution and a solution where the system is installed in advance of subsea deployment.

This is how ClampOn describes system operation: ‘The CEM system consists of up to eight transducers and an electronics unit which handles all signal acquisition and processing. Two and two transducers operate consecutive in a pitch/catch mode of operation giving the average wall thickness of the area between the transducers, which can be up to 2m in length. By choosing the transducer positions with care, normally unavailable areas can be monitored, eg buried parts of a pipeline.

‘Requirements imposed by important factors such as mode separation and spurious arrivals place limits on the maximum and minimum distance between transducers. These limits are functions of pipe thickness and diameter, and need to be decided for each installation in order to be able to maximize coverage area. In most cases the transducers will be placed on two rings around the pipe, and set up to monitor the area between the rings and, if possible, the area along the ring.

‘Because of wave diffraction the covered area stretches beyond the physical dimension of the transducers,' ClampOn adds. ‘Clearly, with the transducers being permanently installed, the coverage area of the system will be a certain fraction of the area over which the system is deployed. Typically, this fraction will be greater than 0.65, or 65%, and can reach almost 90%. OE

TITAN TICKS: Maritime satellite communications
provider Marlink recently confirmed delivery and
installation of its innovative Sealink VSAT system
on the Atlantic Oilfield Services oil & gas support
unit KS Titan 2. The rig, chartered by ExxonMobil,
is the second Atlantic Oilfield Services unit to
install Sealink.
‘Since its installation, the crew have been very
satisfied with Sealink VSAT,’ comments Atlantic
Oilfield Services’ IT manager Partha Rajkumar. ‘The
system provides always-on, reliable connectivity
which is essential to meet the modern demandshttp://www.blogger.com/img/blank.gif
of the digital oilfield. Our positive experience with
Marlink led us to extend our contract to include
the KS Titan 2, with a view to further expanding
the capabilities of the satellite communications
network in the near future.’
The C-band VSAT system will provide the
rig with up to 256Kbps bandwidth and eight
telephone lines for a multitude of critical offshore
applications, including real-time data management
and data sharing with sites ashore.

http://www.oilonline.com/default.asp?id=259&nid=19110&name=Corrosion-erosion+monitor+set+for+subsea

A Snapshot of Brazil Oil Industry

2011-08-19T12:31:00.000-07:00

A Snapshot of Brazil
by Trey Cowan
|
Rigzone Staff
|
Friday, August 19, 2011

Brazilian offshore drilling activities are faring much better than worldwide operations. Total average utilization for Brazil's mobile offshore drilling fleet is 94 percent, which compares quite favorably to the global average of 80 percent. Similarly, average dayrates are much higher in Brazil than compared to the rest of the world. Currently, rigs (i.e. drillships, jackups, and semisubs combined) are garnering rates in the high-$310s while global average dayrates are in the mid-$230s.

The favorable disparity for both operating efficiency and dayrates is due largely to fleet mix. Most of the rigs operating off the coast of Brazil are exploring for oil in deeper waters. Hence, very little drilling in the region is accomplished using jackups; which typically command the lowest dayrates in the industry.

Brazil's semisub fleet utilization (a regional fleet of 52 competitively marketed rigs) is 98 percent, quite high by industry standards. Its drillship fleet, while much smaller at 17 marketed rigs, will continue to grow as newbuild equipment is delivered into the region. The jackup fleet is the smallest of the mix with just three competitive rigs on lease in the region. All three are currently under contract. Given the vast quantity of Brazil's discoveries, demand for offshore rigs shows only signs of growing as the country looks to further tap its ample reserves.
Recent News From the Region

Pacific Drilling announced that its ultra-deepwater drillship the Pacific Mistral has been awarded a three-year contract by Petróleo Brasileiro S.A. (Petrobras) for operations in Brazil. The contract is expected to commence in the fourth quarter of 2011. Estimated maximum contract revenues, including mobilization and client requested modifications, are approximately $536 million.
Rockhopper recently completed interpretation of its fast track new seismic data in PL032 and PL033. Seismic data shows that the Sea Lion Main Complex ("http://www.blogger.com/img/blank.gifSLMC") will extend to the south and a new high case area extends over 90km2. Also, two new fan prospects were identified within the new seismic data, Casper and Kermit. Following completion of drilling operations on well 14/10-6, Rockhopper is committed to drill three further wells using the Ocean Guardian.
Petrobras has commenced production from the P-56 platform at the Marlim Sul field in the Campos Basin. The unit began production through well 7-MLS-163HPRJS and will potentially generate around 16,000 bopd. The P-56 platform, installed in a water depth of 5,479 feet (1,670 meters), is designed to handle up to 100 Mcf/d when it reaches maximum capacity. This is expected to take place in the first quarter of 2012.
The Sevan Brasil, which is under construction at Cosco Shipyard in China, is on schedule to be delivered during the first quarter of 2012. Upon delivery, the rig will set sail for Brazil to begin its six-year contract with Petrobras.
http://www.rigzone.com/news/article.asp?a_id=110348&hmpn=1

Composites Protect Pipe in Downhole Environment

2011-08-12T11:01:00.000-07:00

To tap what remains in an oil well, oil field operators must introduce pressure into the subterranean reservoir — a tactic known as enhanced oil recovery (EOR) or secondary stimulation. One of the most used and effective methods is to pump water into the reservoir through a series of strategically placed injection wells.

Although EOR sounds relatively simple, it introduces several complications: First, the water itself can negatively affect pipe longevity, and depending on the source, level of acidity and/or chemical additive content, may accelerate or exacerbate pipe corrosion. Second, injected water temperature typically ranges from 100°F to 400°F (38°C to 204°C). Third, service pressure can range from 500 psi (34.47 bar) to 10,000 psi (689.5 bar) or more, depending on the application. Given this hostile downhole environment, injector pipe requires substantial engineering, particularly with regard to materials, to accommodate and manage the thermal stress and pressure and optimize service life.

In such difficult and corrosive downhole environments, oil and gas producers have typically relied on pipe made from metal alloys of chrome, stainless steel, or nickel to resist chemical and water attack. The challenge of such materials — particularly of late — has been their high cost as steel prices have steadily increased.

One alternative is a less-expensive, stan-dard steel pipe that is lined with a material able to handle the water pressure and protect the pipe against corrosion.

The engineer says the company first used injectors made of 13 Chrome, a steel pipe that features 13 percent chromium. The injection fluid, saltwater, was plentiful, of course, but “very corrosive to steel,” he recalls.
The company found that it could mitigate some corrosion if it removed oxygen from the water, but it was impossible to produce saltwater that is 100 percent oxygen-free. A pipe made from nickel alloy steel would have fared well, says the engineer, but only at considerable expense. “We were looking for a product we could run in these injection wells to protect against corrosion without the expense of buying nickel alloy tubing.”

That product turned out to be one that this firm had used onshore but never offshore. It comes from DUOLINE Technologies (Odessa, Texas), which 40 years ago started experimenting with glass fiber pipe liners saturated with epoxy resin. The goal was to develop a pipe/liner combination that offers a relatively low-cost alternative to expensive metal alloy pipes but still provides pipe protection for most downhole applications. That effort continued, and the company eventually developed a full line of glass-reinforced epoxy and plastic products for downhole corrosion protection. The heart of DUOLINE’s current product offerings is the DUOLINE 20, a glass-reinforced epoxy liner and pipe combination produced using some creative and innovative manufacturing technologies that have helped the company install more than 75 million ft (22.86 million m) of tubular lining worldwide. Oscar Zapata, DUOLINE’s product engineering manager, notes that the bulk of the company’s business on a unit basis is done in North America, but most of its large-diameter lined pipe is sold outside North America.

source: http://www.compositesworld.com/articles/composites-protect-pipe-in-downhole-environment

IADC Advanced Rig Technology Conference & Exhibition

2011-08-05T07:25:00.000-07:00

IADC Advanced Rig Technology Conference & Exhibition

20 September 2011, Norris Conference Center CityCentre, Houston

The well-construction industry strides forward boldly in advancing technology, with respect to both surface and subsurface tools, automation, and mechanization. However, with each expansion of the technology envelope, we also produce new challenges in reliability, communications protocol, and other areas. The mission of the 2011 IADC Advanced Rig Technology Conference & Exhibition, organized by the IADC Advanced Rig Technology Committee, is to spur dialog on ground-breaking milestones in well-construction technology and foster understanding of the challenges ahead.

Tuesday, 20 September

7 am
Speaker Briefing (Conference speakers, session chairs & moderators only) Magnolia Room

7:30 am
Registration Ballroom Foyer

Coffee Service & Exhibit Viewing Red Oak Ballroom AB

8 am
Welcome, Introductions & IADC Advanced Rig Technology Committee Update

Mike Killalea, Group Vice President/Publisher, IADC

The IADC Advanced Rig Technology Committee comprises three subcommittees – Drilling Control Systems, Reliability & Guidelines, and Future Technology. Each group has over the last three years accomplished numerous goals and projects to the betterment of the drilling industry. In this session, ART officers will brief the audience on past successes and their vision moving forward.

IADC Advanced Rig Technology Committee - Officers

Chairman: David Reid, VP Global Corporate Accounts, National Oilwell Varco
Vice Chairman-Drilling Control Systems: Terry Loftis, Engineering Manager, Transocean
Vice Chairman-Reliability & Guidelines: Robert Urbanowski, Manager, US Operations Engineering, Precision Drilling Oilfield Services Corporation
Vice Chairman-Future Technology: Dustin Torkay, Project Engineer, Archer

8:45 am
Focus on Safety Systems
Session Chair: David Reid, VP Global Corporate Accounts, National Oilwell Varco

Shell Refinery Operations & Safety Critical Controls: Arthur Woltman, Principal Engineer, Shell Global Solutions (US) Inc.

As the drilling industry explores automating operations to improve both safety and efficiency, it is finding much to learn from other industries. Automated operations and critical safety controls have made significant strides in E&P’s sister industry, refining. This presentation will provide a thorough overview of how Shell has tackled remote operations with a focus on safety in its refinery operations.

Critical Well Control Information Display: Goran Andersson, Team Lead, D&C Training Center, Chevron

The display of data to the Driller is abundant and complex, increasing the opportunity for an influx in the wellbore to be missed. The industry’s effort to make all information available has effectually made less information usable. Chevron believes there are key lessons our industry can glean from the aviation industry with regards to the display of critical information in a manner that is obvious and available at all times. Accordingly, we assembled a working team that has developed a standard method to communicate potential well control hazards to the operating crew, by combining Chevron, Transocean, and NOV’s capability to improve upon the working system for Chevron-operated rigs in the Gulf of Mexico.

9:45 am
Coffee Service & Exhibit Viewing Red Oak Ballroom AB

10:15 am
Controls & Integration
Session Chair: Terry Loftis, Engineering Manager, Transocean

A New Class Notation for Software-Dependent Systems: David N. Card, Technical Director, DNV

DNV has developed a new optional offshore rule, OS D-203, Integrated Software Dependent Systems (ISDS) to help ensure the delivery of systems with greater operational reliability. ISDS focuses on two critical aspects of new builds: software quality and systems integration. Software often has not been fully tested by suppliers prior to installation at the yard. Even if each individual software component works as designed, problems may occur because messages, handshakes and parameters are not consistently implemented across systems. Seadrill and Dolphin Drilling have been early adopters of the ISDS approach.

Advancing Technologies in Rig Communications & Protocols: Brad Rosenhagen, Director, Drilling Support Services, AWC Incorporated

Some of the earlier communications and protocols adopted for drilling operations, to potential future technologies to meet continuing demands for better solutions will be presented. Additional information from a survey conducted by IADC in 2008 provides current status on many of today’s rig control systems. Also addressed is the ongoing need for improved communications between drill rig tools, monitoring and controls systems to provide reliable, efficient and safe operations for drilling. Additionally, a case study will be provided on issues and challenges on developing an industrial communication infrastructure for drilling rigs.

An Open Process Model Approach to Standardization: Barry E. Baker, Director of Engineering, Omron Oilfield & Marine

An open process model and standardization methodology for the drilling industry that allows intellectual property to be protected while preserving an environment that is conducive to competition and collaboration. Several successful examples of collaboration between different stakeholders will be presented to demonstrate the value and benefits that come when the drilling industry embraces an open process model along with a structured and orderly methodology for standardization.

11:30 am
Luncheon & Exhibit Viewing Red Oak Ballroom AB

12:45 pm
Non Productive Time

Why RFID and Why Now?: Frank Breland, Manager, Planned Maintenance, Diamond Offshore Drilling, Inc.

RFID has become the key ingredient in increasing Reliability in the drilling industry. It is one of the only industries that RFID is almost a requirement to increase reliability, maintainability and availability. The reason being that the assets in the drilling industry move as much as they do, and unlike a process plant or a refinery where a boiler or a turbine stays in one location from cradle to grave, capital equipment in the oil field moves like inventory. And the "maintainer" changes from the mechanic on the rig, to the man in the drilling contractor's yard to the OEM's service personnel. And because of the extreme wear and tear in the industry most styles of identification, Serial Numbers, Name Plate, Direct Part Marking etc., usually get knocked off or wear out after a few years and there is no way to identify the asset. Maintenance history ceases to exist and becomes Maintenance…History. RFID after many trials and tribulations is finally rugged enough and here to stay in the drilling industry, as the key to asset identification and maintenance management.

Using Data to, Increase Reliability and Making Condition Based Maintenance a Reality in the Drilling Industry (Upstream Oil and Gas Industry): Ken Gardner, Manager, Maintenance Strategy & Development, Transocean

Research currently underway that could form the basis of a threshold-based analysis for use in the drilling industry will be described. Current analysis of 3 years of operational data for different drilling assets, starting with the top drive, and identifying operational characteristics that lead to failures will be presented. Then look at plans to correlate this data with maintenance data to get a complete picture on all the parameters that led to the failure. If a correlation is identified between different operational parameters of over 80%, this could be the first steps in the direction toward making predictive maintenance a reality in the drilling industry.

Reliability in Drilling Systems: Walt Aldred, Scientific Advisor & Research Director, Schlumberger

Schlumberger’s director of research for drilling will share his thoughts on challenges in reliability and potential solutions.

NPT: You Can't Fix What You Can't Measure: Bill O’Grady, VP Engineering, & Don Shafer, Athens Group

Respondents to a recent industry survey on non-productive time (NPT) indicated that implementation and reporting of an industry standard calculation of NPT is one of the top opportunities for the industry to collaborate on NPT reduction. During this presentation, we will draw on the successes of the semiconductor, aerospace and automotive industries to propose a standard set of definitions for core drilling process metrics; propose a standard definition of and method for calculating NPT; and propose two new metrics that will provide a better methodology for comparing and improving the performance of drilling assets.

2:30 pm
Coffee Service & Exhibit Viewing Red Oak Ballroom AB

2:45 pm
New Technology & New Processes I

Experience using Hardware in the Loop Test for DP Semi Newbuildings: John R. Pederson, Lead Engineer, Maersk Drilling

Maersk Drilling’s experience and cooperation with the vendors of equipment onboard three (3) Semis and the “Companies” will be explained and the following questions will be discussed during the presentation: Do we get value for money performing these tests and implementation of a new test regime?; How can we control software changes during “Hardware in loop test”?; and finally, What are we testing?; What should be the future requirements to software tests to avoid accidents in the offshore industry?

Hardware-In-the-Loop Testing of Drilling Control Systems: Tom Arne Pedersen, R&D Manager Drilling, Marine Cybernetics AS

Hardware-In-the-Loop (HIL) testing is a well proven test methodology from automotive, avionics, space, robotics, and nuclear industries. It facilitates systematic testing of control system design philosophy, functionality, performance, and failure handling capability, both in normal and off-design operating conditions, and is conducted in a virtual test-bed where there is no risk to man, vessel, or equipment. The concept of independent HIL testing for Drilling Control Systems and interesting test cases for single machines, integrated functionality and anti collision scenarios are presented together with National Oilwell Varco (NOV).

3:30 pm
Coffee Service & Exhibit Viewing Red Oak Ballroom AB

3:45 pm
New Technology & New Processes II

Utilization or Simulator Technology for Performance Optimisation of Drilling Units in Operation: Bjorn Rudshaug, VP Research & Development, Aker Solutions

Simulators for training of rig crews have been in the market for the last ten years, with good results. The training simulators however, are often of a generic type describing the drilling rig's functionality with an accuracy just adequate for training. This paper describes how recent advances in 3-D engineering tools combine with the actual control system of the rig and state of the art visualization. The result is a 1:1 simulator based on the actual engineering drawings of the rig that follows the life cycle of the rig. Typical uses are testing of rig functionality prior to construction, pre-commissioning of software changes prior to installation, training of rig crew, and optimisation of operational sequences to improve operational efficiency based on crew feedback in an offline environment. Case histories and lessons learned are included.

Optimized Rig Technology Gains High Efficiency & Improved HSE: Marco Cercato, Business Development Manager, Drillmec SpA

A unique advanced rig technology offers proven step change in performance, while lowering enviormental impact and enhancing safety. The system's flexibility renders it appropriate across a wide range of environmental conditions and applications, from traditional oil and gas to unconventional gas shales, coal-bed methane and geothermal. Case histories are provided, including a preview of upcoming CBM work in China.
http://www.blogger.com/img/blank.gif
Rig Technology – an Enabler for Factory DrillingTM: Ron Ayllon, Region Manager-The Americas, Rig Management Group, Schlumberger - IPM

Rig mechanization has brought some significant benefits to the drilling process but we are still subject to significant performance variability between rigs, crews, drillers, etc. For Factory DrillingTM, the next leap forward will be the application of drilling automation to deliver consistent performance from well to well. This will require drilling contractors to provide “auto-enabled” rigs that can execute the commands generated by automation algorithms.

5:15 pm
Adjournment
http://www.iadc.org/conferences/ART_2011/

Installation of Fiberglass Line Pipe For Deep Disposal Wells… Proper Installation Ensures Years Of Reliable Performance

2011-07-29T09:17:00.000-07:00

Installation of Fiberglass Line Pipe
For Deep Disposal Wells…
Proper Installation Ensures
Years Of Reliable Performance

Fiberglass liners in downhole tubing have been used since the beginning of the 1970’s in onshore wells in North America. The technology was initially driven by the challenge to ensure longer lifetime of the tubing in applications such as disposal wells.

Simply described: the liners are inserted in the steel tubing and are locked in place with a cement layer that is filled in the annulus. The ends of the GRE-liner are covered with flares for mechanical protection against well operations. A corrosion barrier ring protects the couplings. The solution is adapted to various coupling and connector types both standard API 8rd and premium (gas tight connections). Typical lengths of the tubulars are 10-12 m.

It is important to emphasize some important facts about fiberglass tubing:

The liner is not chemically bonded to the carbon steel, but is restricted in movement by the cement and the barrier rings at each connection.
The corrosion barrier ring and flare system is not completely gas and fluid tight. This allows for some small amount of corrosive fluids and gases to enter into the connection area and under the liner.
The cement layer is already present with a high pH that will quickly stop any corrosion, since the fluids are not replenished.
The annulus is in equilibrium with the bore so no new gas or fluids will enter.
The fact that there is some communication also prevents large differential pressures to build up behind the liner. The risk for collapse of the liner is therefore limited.

In September 2005 Rice Operating Company installed 3,900 foot of 5.5” Duoline® 20 fiberglass lined pipe for a new disposal well just southwest of Eunice, NM. The installation was completed in one day with a regular pulling unit crew, plus a factory trained technician.

Experience over the years indicates that to ensure the integrity of the installation it is advisable to have a factory trained installer involved in the project from the beginning. Duoline Technologies provided us with a professionally trained installer.

One of the most important considerations for any corrosion resistant piping system is protection of the connection area. This can be achieved by employing a reinforced elastomeric corrosion barrier ring (CBR), which is compressed between the liners in the connection make-up process. This compressed CBR is held in place by the liner, and prevents passing fluids from causing the all-too-common coupling failure.

Using a stabbing guide is essential to make certain that the pipes do not clash together and damage the flare. This guarantees the best connection possible in order to reduce the chance of any corrosion to the pipeline.

Users have found that pipe that arrives from the factory with the measurement line already marked makes the installation go faster and smoother. The measurement line is the deepest point the pipes should be threaded in order to correctly protect the corrosion barrier ring.

Lastly, the drift is inserted into the pipe to determine the status of the corrosion barrier ring. If the drift can not be dropped through to the next pipe layer without hesitation the installation of the pipe must start over with a new corrosion barrier ring in place since it is highly likely the ring was damaged during the make-up of the connection.

Fiberglass lined pipe, once properly installed by a trained crew, can last more than 30 years in the field without corrosion damage to the exterior pipe. It is more cost effective to take the time to install it correctly during the first round than having to come back and re-install a replacement because it had become corroded.

For additional information about DUOLINE® Technologies visit: www.duoline.com

Fiberglass Reinforced Plastic for Corrosion Resitance

2011-07-22T12:46:00.000-07:00

First Part-- Visit for full article
http://www.ifs-frp.com/PDFs/ReinPlasCorrResis.pdfhttp://www.blogger.com/img/blank.gif

RICEWRAP®--- PROTEÇÃO EXTERNA ANTICORROSÃO

2011-07-15T13:04:00.000-07:00

RICEWRAP®---
PROTEÇÃO EXTERNA ANTICORROSÃO
RICEWRAP® - a aplicação de material de polímero reforçado de fibra para o diâmetro externo de artigos tubulares de países produtores de petróleo.
APLICAÇÕES:
Proteção contra corrosão externa para a tubulação de fundo de poço
Excelente para o uso em zonas de finalização dupla

ESPECIFICAÇÕES:

     Material: Fibra de vidro-epoxy com filamento bobinado
     Espessura: Espessura nominal 0,100"
     Resistência química: HCL, CO2, salmoura, H2S e muitos outros
     Temperatura de trabalho: de -29° C (-20° F) a 121° C (250° F).
     Tamanhos: Tubulares de 2-3/8" até 7,0"
     Conexões: Conexões Premium e API

INSTALAÇÃO:
Um anel de barreira anticorrosão externa é utilizado para proteger as roscas da conexão.
Um anel de barreira anticorrosão é comprimido durante a formação de campo.
O anel de barreira anticorrosão satisfaz as necessidades de decomposição e remontagem e sem complicações em campo.
Para maiores informações, visite: www.duoline.com

Se a sua aplicação se encaixar em qualquer uma das seguintes categorias, você tem um motivo para entrar em contato conosco!
Poços de produção de gás e petróleo
Serviço de gás azedo
Plataformas em alto mar
Operações de intervenção em terra firme
Poços de injeção de águas de inundações
Poços de injeção de CO2
Sistemas de descarte da água salobra
Poços de descarte de produtos químicos
Sobre a Duoline®
Desde 1964, mais de 80 milhões de pés de tubulação reforçada revestida com epóxi com vidro da Duoline® foram instalados com sucesso em todo o mundo. Duoline® é uma solução de custo compensador, de alto valor e alta performance que supera o alto custo da corrosão.

Os sistemas da Duoline® oferecem desempenho superior e maior vida útil quahttp://www.blogger.com/img/blank.gifndo comparados às opções menos duráveis de revestimentos de spray. Os sistemas da Duoline® também são internacionalmente considerados uma alternativa de custo-benefício para aços de alta-liga.

Para obter detalhes adicionais sobre os produtos da Duoline®, entre em contato com:

Oscar Zapata, Duoline® Technologies, 250 W Bluebird Rd., Gilmer, Texas 75645-7234. Fone: 903.734.1371 | Fax: 903.734.1571.

E-mail: ozapata@duoline.com

www.duoline.com

Duoline-20® --- Proof of Performance For Internal Protection of OilfieldTubulars

2011-07-08T10:10:00.000-07:00

Gilmer, TEXAS --- Duoline® Technologies, an industry leader in providing oilfield corrosion solutions through innovative products and services, illustrates a sample of corrosion-damaged connection that offers visible proof of the successful performance of Duoline® --- a premium internal corrosion resistant lining system for oil and gas industry.

The photo above features a pipe severely compromised from corrosion attack, The casing itself obtained a leakwhich allowed fluid to migrate through the annulus. Corrosive fluids then attacked the steel tubing while DUOLINE-20® --- designed to protect from within --- remained completely intact

Duoline-20®, manufactured by DUOLINE® Technologies, is a filament-wound fibhttp://www.blogger.com/img/blank.giferglass-reinforced epoxy liner that reliably beats corrosion. Since 1964 more than 100 million feet have been successfully installed world wide as a more robust alternative to plastic coatings, and as a high-performance, high-value, cost-effective alternative to Corrosion Resistant Alloys.

Duoline® is ideally suited for diverse applications such as but not limited to offshore platforms, onshore work-over rigs, sour gas service, oil and gas producing wells, waterflood injection wells, brinewater/chemical disposal wells, CO2 injection wells, saltwater disposal systems.

For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com
Or visit: www.duoline.com

The Well Completions Bottleneck by Trey Cowan Rigzone Staff

2011-06-24T07:57:00.000-07:00

The Well Completions Bottleneck
by Trey Cowanhttp://www.blogger.com/img/blank.gif
Rigzone Staff 6/22/2011

Link for full piece and graphics: http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.rigzone.com/news/article.asp?a_id=108298

At the height of the 2008 commodity price surge for both oil and natural gas, the inventory of wells drilled but not completed was also tracking above the norm at over 2,000 wells. A primary factor contributing to this backlog was contractual as operators drilled in order to hold their leases in some instances. Additionally, in some regions a shortage of labor and equipment was exacerbating the situation.
The Well Completions Bottleneck

But as the rig count proceeded to drop at an unprecedented rate during the later half of 2008, the industry was then able to work through the backlog over the ensuing months. An unintended consequence was that, as operators worked through their excessive inventories of uncompleted wells, natural gas production climbed while the natural gas rig count fell dramatically. The saying "History never repeats but it sure does rhyme," applies well to this scenario. But this time around the trends point to U.S. oil instead of natural gas experiencing production increases when the rig count eventually slows.
The Well Completions Bottleneck

According to Halliburton, the number of uncompleted wells in the United States was approaching 3,500 wells at the end of 1Q11. Given that the type of drilling underway has changed dramatically over the last four years (with horizontal drilling now comprising a significant portion of the mix) and the high rig count in general, we anticipate that the backlog for completions will continue to grow (as long as drilling continues to be undertaken at a faster pace than capital expansion by oilfield service providers). The relevance of this situation is even greater when you consider that the service intensity necessary to complete wells has doubled what it was on average two years ago.

As of the most recent count there were approximately 1,800 land rigs drilling in the lower 48 states for oil and gas. If you assume that each frac crew can complete six wells in the average time it takes to drill one well, then the equilibrium point for the number of frac crews in the lower-48 would be the number of horizontal and directional rigs drilling in US divided by 6.

Recent estimates peg the total horse power (hp) across North America available for stimulating wells at approximately 9 to 10 million. If you consider that between 25k to 40k hp is needed to stimulate each horizontal shale well, then that places the total number of frac crews covering North America somewhere in the neighborhood of 300 crews. Backing out a healthy figure for what are likely Canadian crews implies that there are at least 200 fracing crews available to complete wells in the US. Thus, as long as the unconventional count is over 1,200 rigs, then we would anticipate that the backlog for completions would continue to grow.

Currently there are approximately 1,300 rigs drilling unconventionally. This would suggest that the current back log will continue to grow by 100 uncompleted wells per month. At this pace the backlog could top 4,000 wells before the start of calendar 2012. What is different about this build up compared to 2008 is that the composition of wells favors oil, condenstates, and NGLs. If you assume that the composition mirrors the rig mix, then over half the uncompleted wells will eventually produce oil.

During 2009 there were over 363,000 wells that produced nearly 1.7 billion barrels of crude in the lower 48 states. That equates to about about 12 barrels per day per well. However, you have to remember that over 2/3 of the existing oil wells are producing at marginal rates. So, using a higher average production of 200 bpd per uncompleted oil well would imply 400,000 barrels per day of production (~2,000 uncompleted oil wells x 200 bpd) untapped at the end of 2011. To put this in perspective, 400,000 bpd of oil would raise current U.S. production of 5.6 million bpd by 7 percent.

The implications of these trends points to a continude rise in prices for fracturing services and supplies. Current estimates place the amount of water used to fracture a well at 4,000,000 million gallons. Proppants (sand or ceramic) used hold the fissures open weigh approximately 5,000,000 lbs. per well. Usage of both is likely to continue rising considering that both the number of frac stages and the lateral lengths drilled are increasing. While there are several items going down the well during the hydraulic fracturing process, the largest component of the mix is definitely water.
The Well Completions Bottleneck
VIEW FULL CHART

We mentioned that the service intensity has increased over the past two to three years. Bilateral wells, zipper-fracs, and longer laterals with more stages/production zones are all contributing to the increased requirements for both equipment and materials.
The Well Completions Bottleneck

Keeping this growth in mind, we have provided an estimate of the largest pressure pumping providers across North America in 2011. Halliburton leads the oil services industry possessing one-fifth of all North American pressure pumping horsepower. And even though the industry is speckled with a multitude of small operators, we note that Spears estimates that nine firms control approximately 80% of the North American market. The smallest of the top nine is Patterson-UTI, which increased its pressure pumping capacity with the purchase of Key Energy's well stimulation business last year.
The Well Completions Bottleneck

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Operators Look to Unlock Tuscaloosa Marine Shale Potential - June 20

Costs For Drilling The Eagle Ford - June 20

Louisiana Fracking Program - June 21

Horizontal Boon Continues - June 21

Horizontal Drilling Boosts Apache's Permian Production - June 22

The Well Completions Bottleneck - June 22

North Dakota Booms into Energy-Rich Era - June 23

Drilling the Louisiana Haynesville - June 23

Private E&P Companies May Sell Niobrara Assets - June 24

Drilling the Texas Haynesville - June 24

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Oil Council: Industry entering phase of "Darwinian" competition

2011-06-17T05:03:00.000-07:00

May 17, 2011 - The Oil Council, the world’s leading network for business development within the global oil and gas industry, recently announced the findings from its May 12 press briefing. According to participants of the briefing organized by The Oil Council and Willis Global Energy, the oil and gas industry is in a period of Darwinian competition where survival will be determined by those most able to adapt to the rapidly changing landscape.

Speaking at the briefing were Dougie Youngson, Director, Oil & Gas, Arbuthnot Securities; Gavin Graham, Executive Vice President, Petrofac Energy Developments; Laurie McFadden, Partner and Co-Head, International Energy and Natural Resources, Freshfields; Mike Karaiskos, Director, Energy and Resources, Deloitte; and Tim Chapman, Managing Director and Head, International Energy, RBC Capital Markets.

The mission to secure oil resources, driven chiefly by Asian NOCs who are long on dollars and short on reserves, was cited as the dominant feature of the current oil and gas climate. Mike Karaiskos said that KNOC’s hostile takeover of Dana Petroleum last year, though unprecedented, was just the beginning of the shopping list. “http://www.blogger.com/img/blank.gifWe see them at every auction, they are backed by deep pools of capital, and they are able to pay prices no one else can pay” said Laurie McFadden, “the question is, how will IOCs react?”

Dougie Youngson said IOCs must adopt an ‘if you can’t beat them, join them’ attitude, anticipating many more JVs between IOCs and NOCs as the latter seek to gain access to new technologies and expertise, especially regarding shale gas and deepwater exploration. Tim Chapman agreed, saying that oil companies are now using NASA-like technology in unconventional plays, citing innovation and technology advancements as key components to new industry growth.

http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://ogpn.baumpub.com/news/1330/oil-council-industry-entering-phase-of-quotdarwinianquot-competition

MaxTube is a licensee of DUOLINE TECHNOLOGIES lining systems.

2011-06-10T06:19:00.000-07:00

The DUOLINE lining system is an innovative technology that has been developed to maximise the performance and reliability of downhole tubulars from corrosion.http://www.blogger.com/img/blank.gif

DUOLINE is a lining system in which a liner is inserted inside carbon steel tubing combining the high strength of steel with the inert properties of the liner to provide effective, long lasting corrosion protection.

http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.maxtube.com/

Duoline® Technologies Now ISO 9001:2008 Certified

2011-06-03T13:37:00.000-07:00

Duoline® Technologies, an industry leader in solving oilfield corrosion problems through innovative products and services, announces that Duoline is now ISO http://www.blogger.com/img/blank.gif9001:2008 Certified. Duoline was audited through TÜV SÜD America Inc. a globally recognized testing, inspection and certification organization offering the highest quality services for a wide range of industries worldwide.

To view the certificate online visit:

http://www.tuvamerica.com/

According to David A. Marshall, president of Duoline® Technologies: "ISO 9001:2008 proves, through documentation, that our Duoline® product consistently meets customer needs as well as all applicable statutory and regulatory http://www.blogger.com/img/blank.gifrequirements."

Since 1964, more than 100 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide. Duoline® --- premium internal corrosion resistant lining system for oil and gas steel tubing --- is a high performance, high-value, cost-effective solution to beating the high cost of corrosion. The unique Duoline® insert liner process creates a proven corrosion barrier inside the steel pipe. The benefit is isolation of corrosive oilfield fluids and gases from the steel.

For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com Or visit: www.duoline.com

DUOLINE® TECHNOLOGIES AND PRECISION LINING SYSTEMS, LLC ESTABLISH RELATIONSHIP TO PROVIDE LINING SYSTEMS TO PERMIAN BASIN OILFIELD COMPANIES

2011-05-27T06:27:00.000-07:00

DUOLINE® TECHNOLOGIES AND PRECISION LINING SYSTEMS, LLC

ESTABLISH RELATIONSHIP TO PROVIDE LINING SYSTEMS

TO PERMIAN BASIN OILFIELD COMPANIES

Gilmer, TEXAS --- Duoline® Technologies announces that on October 6, 2010, Precision Lining Systems, LLC purchased from Duoline® Technologies, a 20-acre property at 9019 N. West County Road in Odessa.

From that location Precision Lining Systems, LLC will market and sell Duoline® fiberglass lining systems together with reclamation services to install Duoline® in new and used oilfield tubulars. Full employment will be maintained at the current Duoline® facility in Odessa thereby ensuring continuity of product quality and customer service.

According to David A. Marshall, president and COO of Duoline® Technologies: "This relationship will preserve reliable availability of the unique Duoline® product for oilfield companies in the Permian Basin. By maintaining, through Precision Lining Systems, LLC, our long-standing hub of manufacturing in Odessa, our customers will benefit from ready-accessibility of products in west-Texas as well as from our newly expanded 130,000 square foot east-Texas facility in Gilmer."

Mr. Marshall notes that Duoline® liners are produced with optimum quality supported by systems that provide repeatability, precision and traceability. Duoline® Technologies is ISO 9001:2008 certified

Duoline® is a premium internal corrosion resistant lining system for oil and gas steel tubing developed as a high performance, high-value, cost-effective soluthttp://www.blogger.com/img/blank.gifion to beating the high cost of corrosion and extending the service life of tubulars. Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide.

For more details contact: David A. Marshall, Duoline® Technologies, 800-345-7423.

E-mail: dmarshall@duoline.com.

Websites:http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.duoline.com/

www.precision-coatings.com

White Paper on Class I Non-Hazardous Injection Wells

2011-05-20T06:07:00.000-07:00

White Paper on Class I Non-Hazardous Injection Wells Montgomery County, Texas CROW - Citizen Residents Opposed to Wells
and Lee M. Miller, Sam Houston State University
As the Texas Commission for Environmental Quality undergoes the 2010 Sunset Review process, concerned citizens of Montgomery County have met to discuss their recommendations
for changes to TCEQ's organizational structure, regulations and processes. The suggested changes are the direct result of five years of interaction that this area has had with the agency.
(Please refer to attached time line for a description of major events shaping the recommendations made here.)

httphttp://www.blogger.com/img/blank.gif://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.sunset.state.tx.us/82ndreports/tceq/responses/112.pdf

A New Animated 3D video From Duoline® Technologies Now Available For Online Viewing: Demonstrating an API Connection with Duoline® 20

2011-05-15T17:41:00.000-07:00

Gilmer, TEXAS --- Duoline® Technologies, an industry leader in solving oilfield corrosion problems through innovative products and services, announces thttp://www.blogger.com/img/blank.gifhe availability of a new animated 3D video for online viewing. The 3D video demonstrates an API Connection with Duoline® 20.

To view online visit:
http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.duoline.com/

The workhorse of the DUOLINE® lining systems. DUOLINE® 20, developed by Duoline Technologies in 1971, is targeted for more demanding corrosive downhole environments. The DUOLINE® 20 system has a proven track record in a great number of demanding environments including water injection, CO2 injection, gas production, gas-lifted oil production and chemicaldisposal wells, onshore and offshore. DUOLINE® 20 has an outstanding performance history in environments containing produced fluids and gasses with CO2 and H2S. DUOLINE® 20 has successfully prevented corrosion in gas production wells with BHT as high as 292°F (144°C), and is typically used in water injection and gas production service up to 250°F (121°C).

The DUOLINE® 20 liner is fabricated exclusively by Duoline Technologies. The liner is a GRE composite (glass reinforced epoxy resin system) manufactured with a filament winding and high temperature cure process. The only fiberglass-epoxy lining system in the marketplace today with over 33 years of accumulated field history. Duoline Technologies and DUOLINE® 20 have pioneered the trend for fiberglass-liner acceptance around the world. DUOLINE® 20 is manufactured and available in a number of international locations.

DUOLINE® 20 has proven to be the most abrasion resistant coating or lining product in downhole wireline trials in deviated wells. It is acid compatible, impact resistant, resistant to gas service failures common to other coatings or linings, premium connection compatible, chemically resistant and tolerant to common tension and bending loads. Quite simply, DUOLINE® 20 offers unsurpassed corrosion protection by a lining system.

Since 1964, more than 100 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide. Duoline® --- premium internal corrosion resistant lining system for oil and gas steel tubing --- is a high performance, high-value, cost-effective solution to beating the high cost of corrosion. The unique Duoline® insert liner process creates a proven corrosion barrier inside the steel pipe. The benefit is isolation of corrosive oilfield fluids and gases from the steel. In addition, Duoline is now ISO 9001:2008 Certified.

For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com
Or visit: www.duoline.com

Marcellus Shale - Appalachian Basin Natural Gas Play New research results surprise everyone on the potential of this well-known Devonian black shale.

2011-05-06T06:53:00.000-07:00

Super Giant Field in the Appalachians?

A few years ago every geologist involved in Appalachian Basin oil and gas knew about the Devonian black shale called the Marcellus. Its black color made it easy to spot in the field and its slightly radioactive signature made it a very easy pick on a geophysical well log.

However, very few of these geologists were excited about the Marcellus Shale as a major source of natural gas. Wells drilled through it produced some gas but rarely in enormous quantity. Few if any in the natural gas industry suspected that the Marcellus might soon be a major contributor to the natural gas supply of the United States - large enough to be spoken of as a "super giant" gas field.

http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://geology.com/articles/marcellus-shale.shtml

Corrosive Gases and Microbes

2011-04-29T10:10:00.000-07:00

Found this on New Mexico Tech site:

Corrosive Gases and Microbes

There are many unique environments in the oil field industry where corrosion commonly occurs. Oxygen (O2) , which is a strong oxidizer, is one of the most corrosive gases when present. Other common corrosive gases in the oil field are carbon dioxide (CO2) and hydrogen sulfide (H2S), which form weak acids in water. Microbial activity may cause corrosion alone, create more corrosive gases, and/or act to induce blockage within pipes.http://www.blogger.com/img/blank.gif

Corrosion rates of steel versus oxygen, carbon dioxide, and hydrogen sulfide. Note the different gas concentrations on the x axis.

This page contains links to pages that discuss the effects of these factors, where they commonly occur (such as wells, tanks, separation facilities, and flow lines), what common types of corrosion occur with these present, and some mitigation techniques. Multiple types of corrosion can occur in all these environments, e.g., pitting and galvanic corrosion. For more on the theory and mechanisms for each corrosion type, go to the theory page.

To learn more:
http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://octane.nmt.edu/waterquality/corrosion/gases.htm

WHEN DO YOU NEED THERMOLINE®?

2011-04-22T08:25:00.000-07:00

WHEN DO YOU NEED THERMOLINE®?
• Do you need to keep your flowing fluids warm?
• Do you need to keep the tubing bore cool?
• Do you need to reduce problems associated with paraffin or hydrathttp://www.blogger.com/img/blank.gife buildup?

If so --- Thermoline® is the answer to your challenges in subsea
flow lines, deep-water tubing strings, chemical plants and other
applications requiring thermal insulation.

Thermoline®- A unique lining system with specialized grout formulation enhances thermal insulation when used with the proven protection of DUOLINE® downhole tubular liners.

Visit Duoline for More Info: http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.duoline.com/

SPE Technology Focus April 2011 Offshore Drilling and Completion

2011-04-15T11:49:00.000-07:00

It has been a year since a tragic event in the Gulf of Mexico triggered the industry
to rethink procedures and regulations on offshore drilling and completion
around the world. Our evolution process has been marked by learning from mistakes,and that event should be no exception. Questions such as “What should we do differently to reduce risks?” and “Is there a safer way to perform
this operation?” should be always asked, regardless of statistics that indicate
we have been doing a good job. There is always room for improvement, and when dealing with lives—whether human, plant, or animal—there should be no limits.

The event last year also triggered more discussion and awareness about well integrity, including about how wells should be designed and constructed to face natural events. Hurricanes, earthquakes, and tsunamis are examples of natural events that we must take into account when designing and constructing
a well. Most engineering structures that greatly affect the environment and
human lives (e.g., buildings, dams, and airplanes) are designed considering parameters involving several times the expected life time of that structure, and with a generous safety margin when uncertainties exist. An offshore well falls
into this category, regardless of how you analyze or look at it.

Understanding the challenges of the environment where we will construct our well, looking at available options and technologies that can reduce the risks, and learning from experiences are three basic steps that we should always take. The papers selected here try to cover these three aspects.
Offshore Drilling and Completion additional reading visit:

http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.spe.org/jpt/print/index.php

New Conference Explores Arctic Potential, Challenges, and Research Stephen Rassenfoss, JPT/JPT Online Staff Writer, and Gentry Braswell, JPT Online T

2011-04-08T11:31:00.000-07:00

At the first ever Arctic Technology Conference (ATC), the talk was about the Arctic’s potential, its challenges, and the technology needed to solve them.
The resolve of those at the conference was aptly summarized
by the title of a speech, “Rejuvenating Arctic Exploration: Less Ice, More Hydrocarbons,”delivered during the opening plenary session by Marc Blaizot, senior vice president of geosciences at Total.

The ATC, a spinoff of the Offshore Technology Conference (OTC) held 7–9 February 2011 in Houston, drew more than 1,000 people from around the globe. Like the OTC, it was created around a challenge that will demand an unusually high level of innovation and cooperation among competitors.

Shell’s delayed exploration program in the Chukchi Sea is an example of the promise and problems that drew attendees together. “In the Gulf of Mexico, there are prospects covering a part of one (lease) block. In the Chukchi, there are prospects covering tens of blocks. And it is a working petroleum system taking away a significant portion of the risk,” said David Lawrence, executive vice president of exploration and commercial for Shell’s Upstream Americas.
The regulatory risk, though, remains sizable. Shell recently postponed drilling for another year for lack of an air permit, after spending five years and USD 50 million on an air quality study.
For now, ATC presentations by Shell experts in a range of fields showed the company moving forward on advanced analysis of its seismic work to better identify targets, a new generation of vehicles capable of traveling farther over highly unpredictable terrain, and even ways to dampen underwater sounds to lessen its impact on wildlife.
For Lawrence, the bottom line remains: “The size of the price in the Arctic is worth it.”
For full article visit:
http://tinyurl.com/67sm65o

Offshore Logistics: Winds of Change

2011-04-01T08:24:00.000-07:00

Offshore Logistics: Winds of Change
The remoteness of offshore projects makes transporting supplies an extremely challenging task. Ian McInnes picks the threads of a very complicated supply chain.

The very remoteness of an offshore site, weather conditions and the difficulty of marrying the, "just in case," and, "just in time," elements of a complicated supply chain can be a smooth well-thought out operation or descend into chaotic panic as supply chain integration and communication fails.

High oil and, previously, natural gas margins have enabled energy companies, their contractors and suppliers to pay whatever is needed to get the job done. Post Deepwater Horizon, and with the ensuing National Commission report, which implicated an incorrect grade of cement and other logistical mistakes as the cause of the disaster, getting materials wrong is no longer an option.
Key offshore logistics challenges

DHL's energy sector senior vice president Steve Harley believes that visibility of assets is just one of the key logistical challenges for offshore oil and gas installations.

"I would focus on visibility. Keeping visibility of material movements, keeping visibility of movements of vessels, helicopters as well," said Harley.

"I think it's also the reach, the access to sites, which are increasingly hard to access. Consequently the implementation of new projects in these locations is a particularly grave logistics challenge to mobilise materials, people and equipment. If it's very difficult to react to a problem, people perhaps don't take the right steps if the logistics are complicated. If the logistics are easier people probably can take more precautions more easily." Harley said.

For full article visit:http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.hydrocarbons-technology.com

A New Animated 3D video From Duoline® Technologies Now Available For Online Viewing:

2011-03-25T06:21:00.000-07:00

A New Animated 3D video From Duoline® Technologies Now Available For Online Viewing:

Demonstrating Premium Connection with Duoline® 20

Gilmer, TEXAS --- Duoline® Technologies, an industry leader in solving oilfield corrosion problems through innovative products and services, announces the availability of a new animated 3D video for online viewing. The 3D video demonstrates a Premium Connection with Duoline® 20.

To view online visit:

http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.duoline.com/

HOW DOES DUOLINE®20 WORK?

Duoline® 20, manufactured by DUOLINE® Technologies, is a filament-wound Glass-Reinforced Epoxy (GRE) liner which is installed to OCTG in corrosive service. It is widely accepted that GRE lining is a more robust alternative to internal plastic coating. DUOLINE® 20 is a very effective corrosion barrier with a long history of tubular protection in a variety of offshore and land based applications. Proven performance leader in corrosive (gas/fluid) injection and disposal for offshore and land-based applications.

Where Will You Benefit From Using DUOLINE®20?

· 250°F working temp

· CO/Water injection/Disposal

· Chemical disposal

· Gas Production

· API or Premium Thread Compatibility

Why Use DUOLINE®20?

· 35 year proven field history

· Lower cost alternative to CRA

· Durable/Long lasting corrosion protection

· Most complete corrosion package on the market

· Most abrasive resistant lining system available

Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide. Duoline® --- premium internal corrosion resistant lining system for oil and gas steel tubing --- is a high performance, high-value, cost-effective solution to beating the high cost of corrosion. The unique Duoline® insert liner process creates a proven corrosion barrier inside the steel pipe. The benefit is isolation of corrosive oilfield fluids and gases from the steel. In addition, Duoline is now ISO 9001:2008 Certified.

For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com
Or visit: www.duoline.com

Free webinar on how to use the Corrosion Analysis Network

2011-03-18T07:27:00.000-07:00

Free webinar of ASM

All

ASM offers a free webinar on how to use the Corrosion Analysis Network and all the knowledge of ASM in the field of corrosion and materials to solve corrosion related problems.

As follow up to NACE CORROSION 2011, this informative webinar demonstrates how you can research and identify solutions to real-world corrosion problems.

The webinar will feature a case study demonstrating how the Corrosion Analysis Network resources can be used to investigate, analyze and solve corrosion-related problems and how use of CAN tools and content reduces the time needed to understand a specific situation, identify candidate solutions, and select the best answer with confidence.

For more info:
http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.linkedin.com/groups?gid=1011577&mostPopular=&trk=tyah

New Book on Corrosion in Oil and Gas Production

2011-03-11T05:47:00.000-08:00

Metallurgy and Corrosion Control in Oil and Gas Production
John Wiley and Sons Ltd, Feb 2011, Pages: 296

This book is intended for engineers and related professionals in the oil and gas production industries. It is intended for use by personnel with limited backgrounds in chemistry, metallurgy, and corrosion and will give them a general understanding of how and why corrosion occurs and the practical approaches to how the effects of corrosion can be mitigated. It is also an asset to the entry-level corrosion control professional who may have a theoretical background in metallurgy, chemistry, or a related field, but who needs to understand the practical limitations of large-scale industrial operations associated with oil and gas production. While the may use by technicians and others with limited formal technical training, it will be written on a level intended for use by engineers having had some exposure to college-level chemistry and some familiarity with materials and engineering design.
To purchase the book visit:
http://www.duoline.com/_SocialWelcome/?socnet=blogspot&soclink=http://www.researchandmarkets.com/research/143b7d/metallurgy_and_corrosion_control_in_oil_and_gas

HOW DOES DUOLINE® 20 WORK?

2011-03-04T11:38:00.000-08:00

HOW DOES DUOLINE® 20 WORK?
Duoline® 20, manufactured by DUOLINE® Technologies, is a filament-wound Glass-Reinforced Epoxy (GRE) liner which is installed to OCTG in corrosive service. It is widely accepted that GRE lining is a more robust alternative to internal plastic coating. DUOLINE® 20 is a very effective corrosion barrier with a long history of tubular protection in a variety of offshore and land based applications. Proven performance leader in corrosive (gas/fluid) injection and disposal for offshore and land-based applications.

Where Will You Benefit From Using DUOLINE®20?
• 250°F working temp
• CO/Water injection/Disposal
• Chemical disposal
• Gas Production
• API or Premium Thread Compatibility

Why Use DUOLINE®20?
• 35 year proven field history
• Lower cost alternative to CRA
• Durable/Long lasting corrosion protection
• Most complete corrosion package on the market
• Most abrasive resistant lining system available

Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide. Duoline® --- premium internal corrosion resistant lining system for oil and gas steel tubing --- is a high performance, high-value, cost-effective solution to beating the high cost of corrosion. The unique Duoline® insert liner process creates a proven corrosion barrier inside the steel pipe. The benefit is isolation of corrosive oilfield fluids and gases from the steel. In addition, Duoline is now ISO 9001:2008 Certified.

For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com
Or visit: www.duoline.com

New Informative DVD Features Duoline® Technologies' Facilities And Capabilities Expansion

2011-02-25T09:04:00.000-08:00

New Informative DVD Features

Duoline® Technologies' Facilities And Capabilities Expansion

Gilmer, TEXAS --- Duoline® Technologies, an industry leader in solving oilfield corrosion problems through innovative products and services, announces the availability of a new DVD that provides details on its new expanded manufacturing facility in Gilmer, TX.

Duoline Technologies®
EXPANDED FACILITIES.

*An ultramodern new 130,000 square foot manufacturing facility now open and producing.
*Located in Gilmer, Texas, only four hours from the major shipping port of Houston, Texas; five hours from New Orleans, Louisiana.

NEW CAPABILITIES

*Unique, highly-efficient Fiber Glass Reinforcement (FRP) manufacturing systems supported by advanced process controls.

*Automated to provide repeatability and precision.

*Full range of traceability

*Incorporates tried, tested and proven technologies for optimum productivity.

*Quality checkpoints built into the production process.

*ISO9001:2008 certified

For more details on the expanded facilities please visit:

http://www.duoline.com/NewFacility.cfm

Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide. Duoline® --- premium internal corrosion resistant lining system for oil and gas steel tubing --- is a high performance, high-value, cost-effective solution to beating the high cost of corrosion. The unique Duoline® insert liner process creates a proven corrosion barrier inside the steel pipe. The benefit is isolation of corrosive oilfield fluids and gases from the steel.

For a free copy of the DVD or for additional information about Duoline® products or services contact: Oscar Zapata: BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com
Or visit: www.duoline.com

DUOLINE TECHNOLOGIES... WHO WE ARE

2011-02-18T05:39:00.000-08:00

DUOLINE TECHNOLOGIES... WHO WE ARE
Company Profile

Duoline Technologies, a member company of the Robroy Industries Group, found its beginnings in the oilfield industry designing, installing and operating produced saltwater gathering & disposal systems since 1953. Through these endeavors, Duoline Technologies developed the DUOLINE lining process in 1964 as a means to solve our own downhole steel tubular corrosion problems. Since that time we have installed more than 75 million feet of DUOLINE tubing worldwide. DUOLINE's unmatched performance has made it the most successful system for prevention of downhole tubular corrosion.

Headquartered in Gilmer, Texas, Duoline Technologies have combined forces with three international partners who each will provide DUOLINE products and services for their respective territories. MaxTube Ltd. , with a DUOLINE lining facility base in Scotland and U.A.E. provide Duoline service to the North Sea, Europe, and the Middle East. Duoline Technologies and PanMarine Equipamentos e Servicos Ltda, in Rio de Janeiro, Brazil jointly operate a DUOLINE lining facility in the state of Sergipe, Brazil, near Aracaju. Rice Engineering & Operations LTD. operate a Duoline lining facility in Edmonton, Alberta, Canada.

The link offers a complete listing of Duoline Technologies offices and locations:
http://www.duoline.com/ContentGather.cfm?navid=4&sublinkid=74

Composites Demonstrate Value In Gulf

2011-02-11T05:45:00.000-08:00

HOUSTONThe offshore areas of the United States are estimated to contain significant quantities of resources in yet-tobe-discovered fields. In fact, the U.S. Minerals Management Services estimates of oil and gas resources in undiscovered fields on the Outer Continental Shelf (2006 mean estimates) total 86 billion barrels of oil and 420 trillion cubic feet of gas. These volumes represent 60 percent of the oil and 40 percent of the natural gas resources estimated in remaining undiscovered fields in the United States.
Harsh wave conditions, deepwater drilling depths, high pressures and temperatures along with a very corrosive environment, make exploring for petroleum in the Gulf of Mexico a difficult challenge. In order to economically develop oil production in deep- and ultradeepwater locations such as the Gulf, the industry needs strong, lightweight materials to replace the heavy alloys traditionally used in offshore platforms. For example, ---
To see the entire piece visit:
http://www.duoline.com/

Glass Reinforced Epoxy Lined Tubing Proven to be an Alternative to Corrosion Resistant Alloys

2011-02-04T10:56:00.000-08:00

Glass Reinforced Epoxy Lined Tubing Proven to be an Alternative to Corrosion Resistant Alloys

Oscar Zapata
Product Engineering Manager
Duoline® Technologies
ozapata@duoline.com

Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing has been successfully installed worldwide. We therefore feel that we have solid understanding of the needs of the industry. However, along with the rest of the industry, we are beginning to see more of our customers move into deepwater drilling which is a very harsh and corrosive environment. As a result, the industry requires new and different kinds of product-based solutions.

Glass reinforced epoxy (GRE) lined tubing in subsea wells .

Many of our customers who typically have used carbon steel materials for most of their applications have found the need to switch to corrosion resistant alloys (CRA) for deepwater applications. The downside to this choice is that CRA's are significantly higher in price than carbon steel and carry a much longer delivery time. Consequently, those customers have begun to explore alternatives. Testing results are therefore necessary in order to prove a product can perform in this demanding environment.

Because this is a relatively new area of exploration there has been little testing or actual performance results for longevity of products such as glass reinforced epoxy (GRE) lined tubing in subsea wells ---- until now.

It was accepted that for GRE-lined tubulars to succeed in the deepwater market, the ability to use such liners with unmodified premium connections was key. A system was developed by Duoline Technologies, consisting of flares and a corrosion barrier ring, to allow lined tubulars to be used with unmodified premium connections. To prevent fluids from leaking into the liner-pipe interstice, two extended flares (one longer than the other by roughly a factor of three) ensured that the barrier ring was under compression when the connection was properly made-up. Testing for deepwater applications: What follows is a brief description of relevant tests and the resulting qualification of the Duoline® GRE product for deepwater applications. This qualification testing is divided into four major areas. Although not all deepwater applications require qualification in each area, the first planned application of GRE required all of the qualification testing cited below. This first application did not require tubing to be run in triples; the majority of all future applications will.

Temperature Testing

A primary concern for the use of GRE-lined tubing is the potential for degradation of the composite liner under hot, wet conditions. With this in mind the customer used an existing historical model which calculated the loss of mechanical properties that result from hot, wet degradation of the liner. This model, an arbitrary end-of-life criterion of a one third loss of flexural modulus gives a 20 year life at 80ºC (176oF), with each 10ºC (18oF) rise in temperature halving the life of the liner. This interpretation of liner life is acknowledged to be extremely conservative, possibly by a factor of as much as 5 to 10.

The deepwater fields being considered for GRE application had water depths of 3,000 ft t- 6,000 ft. Some of the facilities used a spar design spar with surface wellheads and others were completed with subsea wellheads. Water injection with sand control was planned for these fields. The metallurgical environments for all of the projects required completion equipment manufactured from corrosion resistant alloys (CRA). Generally, 13% chrome metallurgy, was selected for production wells, while the resulting water injection well design required a high strength corrosion resistant alloy or equivalent material. Premium, high compression, gas tight connections were used in the production casing and completions.

Qualification of GRE with unmodified premium connections

Deepwater wells generally require unmodified premium connections due to the extreme tubing loads being experienced. Almost all of the previous experience with GRE-lined tubulars had been in onshore/shallow waters where API 8Rd or modified premium connections were acceptable.

Qualification of GRE in pre-production conditions

Prior to deepwater applications, GRE tubing had not been run under pre-production conditions. "Pre-production" is the initial use of a water injector to produce hydrocarbons. This was not intended for every deepwater field, but was a consideration for the first application of Deepwater GRE. Tests would be required to determine whether the GRE liner could withstand the erosional forces of production fluids. In addition, these tests would also assess whether the erosion risk from produced water re-injection, which traditionally carries more solids than seawater injection.

Qualification of GRE in Fatigue loading

Spar environments introduce fatigue due to dynamic loading and the accompanying cyclic stresses on the tubing in the open water section.

Conclusion and recommendations:

In terms of the verification of the downhole performance of this tubular product, the following criteria were satisfied:

The ring assembly was proven not to affect the performance of the connection or the GRE-Lined tubulars. Therefore, an un-modified premium connection could be used with the GRE liner.

The fatigue loading induced by some deepwater environments, which utilize spars, is within existing product specifications.

The erosional conditions and loadings of pre-production conditions (the initial use of a water injector as a producer) were shown to be within specification.

The final issue to be resolved with the GRE-lined tubulars for deepwater was the need to drift-check each connection after make-up. This was thoroughly examined in the initial deepwater installations, which were carried out from a spar rig.

On a project scope, the cost savings of non-CRA tubing is significant; thus GRE is now running as the qualified product in many other deepwater projects for a variety of operators. As a result of this testing and qualification, GRE lined tubulars are now being used by the majority of our customers deepwater water injection projects with significant cost and delivery time savings.

For full results of the testing visit: www.duoline.com

For additional information about Duoline® products or services contact: Oscar Zapata: 250 W BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com Or visit: www.duoline.com

Duoline Case Study Area

2011-01-28T07:54:00.000-08:00

Welcome to the Duoline Case Histories area, please use the search below to view specific case histories. Please select your criteria from one of the list boxes below. Once a specific criteria has been selected you will be directed to a results page where all of the case histories meeting your criteria will be shown. The case histories will be in either ascending numerical, alphabetical or chronological order depending on the selected search criteria. Use the "View All" option to view all case histories.
http://www.duoline.com/case_studies.cfm

Duoline® Technologies Now ISO 9001:2008 Certified

2011-01-21T07:38:00.000-08:00

Gilmer, TEXAS --- Duoline® Technologies, an industry leader in solving oilfield corrosion problems through innovative products and services, announces that Duoline is now ISO 9001:2008 Certified. Duoline was audited through TÜV SÜD America Inc. a globally recognized testing, inspection and certification organization offering the highest quality services for a wide range of industries worldwide.

To view the certificate online visit:

http://www.tuvamerica.com/

According to David A. Marshall, president of Duoline® Technologies: "ISO 9001:2008 proves, through documentation, that our Duoline® product consistently meets customer needs as well as all applicable statutory and regulatory requirements."

Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide. Duoline® --- premium internal corrosion resistant lining system for oil and gas steel tubing --- is a high performance, high-value, cost-effective solution to beating the high cost of corrosion. The unique Duoline® insert liner process creates a proven corrosion barrier inside the steel pipe. The benefit is isolation of corrosive oilfield fluids and gases from the steel.

For additional information about Duoline® products or services contact: Oscar Zapata: BlueBird Lane, Gilmer, Texas 903-734-1371. Oscar Zapata: ozapata@duoline.com
Or visit: www.duoline.com

Composites Protect Pipe in Downhole Environment

2011-01-14T07:01:00.000-08:00

Photo Caption:Cured and ground liners are then inserted into the host pipe and prepared for grout injection.

The stereotypical Hollywood image of a freshly tapped oil field usually conjures up scenes of a wide-open scrubland dotted with cactus, a blazing overhead sun and a tall wooden derrick. Out of the top of the derrick sprays thick, black crude oil, covering everything around it, while oil-slicked riggers dance and rejoice at having finally struck “black gold.” As this somewhat fanciful image implies, oil and natural gas reserves trapped thousands of feet below ground are subject to hydrostatic pressure. This naturally occurring phenomenon drives the oil or gas to the surface, making it relatively easy to extract. This pressure, however, diminishes over time, even when substantial amounts of recoverable oil or gas still remain in the ground.

To tap what remains, oil field operators must then introduce pressure into the subterranean reservoir — a tactic known as enhanced oil recovery (EOR) or secondary stimulation. One of the most used and effective methods is to pump water into the reservoir through a series of strategically placed injection wells. Used in both land- and sea-based oil and gas extraction, injection wells can range in depth from around 2,000 ft/610m to 17,000 ft/5,182m or more. Several injection wells might be situated in a field to serve one or more production wells. An injector may run continuously in service of an extraction well, or it may run only intermittently.

Although EOR sounds relatively simple, it introduces several complications: First, the water itself can negatively affect pipe longevity, and depending on the source, level of acidity and/or chemical additive content, may accelerate or exacerbate pipe corrosion. Second, injected water temperature typically ranges from 100°F to 400°F (38°C to 204°C). Third, service pressure can range from 500 psi (34.47 bar) to 10,000 psi (689.5 bar) or more, depending on the application. Given this hostile downhole environment, injector pipe requires substantial engineering, particularly with regard to materials, to accommodate and manage the thermal stress and pressure and optimize service life.

In such difficult and corrosive downhole environments, oil and gas producers have typically relied on pipe made from metal alloys of chrome, stainless steel, or nickel to resist chemical and water attack. The challenge of such materials — particularly of late — has been their high cost as steel prices have steadily increased.

One alternative is a less-expensive, stan-dard steel pipe that is lined with a material able to handle the water pressure and protect the pipe against corrosion.
TUBULARS FOR SALTWATER

This is the materials-selection predicament in which a major oil exploration and production company found itself aboard a TLP (tension leg platform) in the Gulf of Mexico. The platform taps oil from a field that had been discovered in the 1980s and had first produced oil in 1996. By 2002, says a completion engineer at the firm who worked on the project, the company had seen signs of “primary depletion” of the reservoir’s natural pressure and had begun to plan for secondary recovery. By 2004, the secondary recovery system was in place, with three injectors serving nine producer wells in three separate reservoirs at depths of 17,000 ft to 18,000 ft (5,182m to 5,486m).

The engineer says the company first used injectors made of 13 Chrome, a steel pipe that features 13 percent chromium. The injection fluid, saltwater, was plentiful, of course, but “very corrosive to steel,” he recalls.
The company found that it could mitigate some corrosion if it removed oxygen from the water, but it was impossible to produce saltwater that is 100 percent oxygen-free. A pipe made from nickel alloy steel would have fared well, says the engineer, but only at considerable expense. “We were looking for a product we could run in these injection wells to protect against corrosion without the expense of buying nickel alloy tubing.”
THE IMPORTANCE OF A LINER

That product turned out to be one that this firm had used onshore but never offshore. It comes from DUOLINE Technologies (Odessa, Texas), which 40 years ago started experimenting with glass fiber pipe liners saturated with epoxy resin. The goal was to develop a pipe/liner combination that offers a relatively low-cost alternative to expensive metal alloy pipes but still provides pipe protection for most downhole applications. That effort continued, and the company eventually developed a full line of glass-reinforced epoxy and plastic products for downhole corrosion protection. The heart of DUOLINE’s current product offerings is the DUOLINE 20, a glass-reinforced epoxy liner and pipe combination produced using some creative and innovative manufacturing technologies that have helped the company install more than 75 million ft (22.86 million m) of tubular lining worldwide. Oscar Zapata, DUOLINE’s product engineering manager, notes that the bulk of the company’s business on a unit basis is done in North America, but most of its large-diameter lined pipe is sold outside North America.

Zapata says the DUOLINE 20 product is not designed to accommodate every downhole application and environment, but it can accommodate many. The liner has successfully prevented corrosion in wells with a bottom-hole temperature (BHT) as high as 292°F/144°C and is used in water injection and gas injection service up to 250°F/121°C. It has performed well in environments with produced fluids and gasses containing CO2 and H2S. The liners that DUOLINE manufactures range in diameter from 1.5 inches/38.1 mm up to 13.375 inches/340 mm depending on the needs of the reservoir, pressure requirements and other factors. Standard pipe lengths are 32 ft and 44 ft (9.8m and 13.4m), although customized lengths are not uncommon. The pipe has been tested to pressures as high as 14,000 psi/965 bar.
At the TLP in the Gulf of Mexico, DUOLINE’s client was looking at pipe water pressures of 7,000 psi/483 bar and, therefore, decided to first test the DUOLINE pipe before actual use in the field. It worked with an engineering firm in Houston, Texas, to pressure cycle the pipe with saltwater. “We looked at how well the fiberglass liner adhered to the base pipe steel,” reports the firm’s engineer. He says that only modest design changes were needed, noting that “last fall we got to a product that satisfied the test results.”

The DUOLINE pipe was installed during November and December of 2007 and, according to the engineer, “ran exactly like a normal tubing string.” The platform’s injectors have an outside diameter (OD) of 4.5 inches/114 mm and, to date, have shown no signs of corrosion. The plan, says the company, is to run the injectors until 2010 and then pull the tubing for normal maintenance and see how the DUOLINE liner is holding up.
ON THE PRODUCTION FLOOR

Manufacture of the DUOLINE 20 involves some sophisticated curing technologies that help the product overcome several challenges of the downhole environment. It starts with a highly polished steel mandrel and a winder. DUOLINE employs seven filament winders, manufactured by Entec Composite Machines Inc. (Salt Lake City, Utah). Single strand rovings of E-glass — 2,000 filament ends per roving, each 0.00065 inch/0.017 mm in diameter — are impregnated with an in-house-formulated epoxy and then wet-wound on the mandrel at alternating angles. Glass fiber is provided by Owens Corning Composite Solutions Inc. (Toledo, Ohio) and PPG Industries Inc. (Cheswick, Pa.), plus several unidentified Chinese suppliers. Zapata says that typically the customer develops a performance specification for glass fiber, then forwards a request for quotes to all suppliers for price, performance and delivery. At least two suppliers are tested for “fit for purpose” and approved to ensure that there is a long-term, uninterrupted supply. Because the environment in which an injector functions can vary depending on water type, chemical use, pressure and temperature, the epoxy/toughener recipe also is varied to provide adequate mechanical strength.

On the mandrel, the angle of the wind is a function of the liner performance requirements specific to optimizing hoop strength and thermal performance. Zapata notes that winding angles change depending on application requirements and that it’s impossible to generalize. Because DUOLINE has been producing liners for so long, the type and variety of winders employed by the company is varied, including, says Zapata, machines not only from Entec, but McClean Anderson (Schofield, Wis.) as well. Zapata says the winders have seen extensive customization over the years to help DUOLINE meet specific application requirements. Liner thickness varies according to the liner’s overall diameter. For example, nominal wall thickness on the 2.251-inch-diameter liner is 0.045 inch/1.1 mm, while the nominal wall thickness of the 5.8-inch-diameter liner is 0.095 inch/2.4 mm.

One of the challenges of using an epoxy-based composite as a liner, says Zapata, is the risk of product failure introduced by voids and poor fiber wetout at or near the surface along the inside diameter of the liner. In a natural gas well, for example, the gas tends to migrate upward into the pipe when water flow is stopped, entering voids via osmosis. Upon decompression, the gas molecules expand, thereby bursting or cracking the liner locally, events that can lead to premature failure. Although liner voids are not as problematic in an oil production environment, minimizing them is crucial: Voids and poor wetout also increase the internal liner surface roughness. Pressure drops caused by increased roughness are a concern to well engineers and must be minimized to maintain optimum well efficiency.

The glass rovings are passed through a resin bath just before they exit the winder head to ensure thorough wetout. The typical fiber/resin ratio is 70:30. When winding is complete, the wound mandrel is removed and placed on the curing table. Here, the company circulates heated oil (350°F/177°C) through the hollow mandrels for about 20 minutes, thereby initiating cure first along the inside diameter (ID) of the pipe to encourage any trapped air to migrate to the liner’s outer surface (Step 4).

“What’s key about it is that we cure from the inside out,” says Zapata. “Air bubbles migrate to the OD and escape. If you cure from the outside in, they start migrating to the ID, you’re restricted by the mandrel OD and air remains trapped in the liner, compromising quality.” DUOLINE verifies the efficacy of its cure with random sample evaluation of void content, checking the percentage of voids per square unit. Target void content is 7 percent or less, which Zapata says the company consistently achieves. “Once the process is set, it’s going to be consistent,” he notes.

Following winding and cure, the liners are put through a process DUOLINE calls “drifting,” where OD imperfections are ground and sanded down to bring the liner into spec and ensure the liner’s OD dimension. Following this is a three-hour batch postcure in an in-house-developed oven, usually at 275°F/135°C. The entire production process takes slightly more than 3.5 hours: 7 minutes to wind, 20 minutes to cure, 10 minutes to drift and three hours of postcure. On a good — and busy — day, DUOLINE can manufacture 600 liners in a variety of sizes.

When liners are ready for installation, they are inserted in metal tubulars and then the pipes are capped and a specially formulated grout is injected into the tubular to fill the annular space between the OD of the composite liner and the ID of the tubular. The grout helps insulate the pipe and mitigates pressure in the liner, transferring it to the pipe, which is the load-bearing member of the assembly. “Internal pressure is transferred through the liner to the grout, and then to the steel pipe,” explains Zapata. The grout fills a space that ranges from 0.040 inch to 1 inch (1 mm to 25.4 mm), depending on pipe diameter and application requirements.
MAKING A CONNECTION

Lining the pipe is only part of the challenge of providing effective downhole tubulars. Segments of pipe must be connected to reach the specified depth. This requires oil field operators to thread together pipe sections. To accomplish this, about 3 inches/76.2 mm of male thread are cut into each end of the tubular. A female-threaded metallic sleeve, or coupling, is then screwed onto one end, which eventually will secure the joint between two pipes.
When the two tubulars are connected, the liner within each pipe must be perfectly sealed to the liner in the adjoining pipe. This is done with two injection molded flanges that are set inside the end of each liner and then flared out to cover the entire exposed edge of the liner. When two tubulars are mated in the field, the male end of the tubular to be added is threaded into the female coupler of the existing pipe. As this is done, the operator inserts between the flanges a corrosion barrier ring (CBR), which provides the liner-to-liner seal. For standard API (American Petroleum Institute; Washington, D.C.) connections, DUOLINE offers an oil-resistant nitrile CBR that incorporates steel wire reinforcements that help the ring hold its shape and resist expansion during pressure cycles. For premium or proprietary threaded connections, the company offers a glass-reinforced PTFE (polytetrafluoroethylene) CBR. The CBR in both cases is designed to accommodate variations in thread makeup in the coupling between two pipes. CBRs are injection molded by a Taiwanese partner. CBR installation in the field is verified by a reference band that’s painted onto the outside of every pipe. If, after the CBR is inserted, the threaded sleeve reaches the reference band, the installation is successful. If the threaded sleeve fails to reach the reference band, then the CBR install was flawed.

Because the actual service life of a tubular, even one with a DUOLINE liner, is application-dependent, the frequency of use, the maintenance schedule of the operator and a variety of other factors not under DUOLINE’s control, the company is hesitant to offer guarantees or estimates of how long its liners will last. Zapata notes that in some cases, oil and gas producers change their pipe every two years whether it needs it or not. Other producers, however, reportedly have left DUOLINE-lined pipe in the hole for 20 years without incident.
THE FUTURE IS BRIGHT

Oil may be expensive, in high demand and less plentiful than it once was, but Zapata says those facts, ironically, are the source of DUOLINE’s optimism about the future. “As we move forward, there will be increased need for glass-reinforced epoxy liners because our fields are being depleted,” he contends. “Demand for enhanced oil recovery will rise, and with it will come a mandate for exploration in deeper and harsher well applications. These demanding applications will require a liner product that can withstand high pressures, depths, temperatures and chemical factors.” DUOLINE is researching alternative materials and manufacturing specifications to produce a product that will meet the demands of such applications.

Article From: Composites Technology
http://www.compositesworld.com/articles/composites-protect-pipe-in-downhole-environment

Duoline:
www.duoline.com

DUOLINE® TECHNOLOGIES AND PRECISION LINING SYSTEMS, LLC ESTABLISH RELATIONSHIP TO PROVIDE LINING SYSTEMS TO PERMIAN BASIN OILFIELD COMPANIES

2011-01-07T05:47:00.000-08:00

DUOLINE® TECHNOLOGIES AND PRECISION LINING SYSTEMS, LLC

ESTABLISH RELATIONSHIP TO PROVIDE LINING SYSTEMS

TO PERMIAN BASIN OILFIELD COMPANIES

Gilmer, TEXAS --- Duoline® Technologies announces that on October 6, 2010, Precision Lining Systems, LLC purchased from Duoline® Technologies, a 20-acre property at 9019 N. West County Road in Odessa.

From that location Precision Lining Systems, LLC will market and sell Duoline® fiberglass lining systems together with reclamation services to install Duoline® in new and used oilfield tubulars. Full employment will be maintained at the current Duoline® facility in Odessa thereby ensuring continuity of product quality and customer service.

According to David A. Marshall, president and COO of Duoline® Technologies: "This relationship will preserve reliable availability of the unique Duoline® product for oilfield companies in the Permian Basin. By maintaining, through Precision Lining Systems, LLC, our long-standing hub of manufacturing in Odessa, our customers will benefit from ready-accessibility of products in west-Texas as well as from our newly expanded 130,000 square foot east-Texas facility in Gilmer."

Mr. Marshall notes that Duoline® liners are produced with optimum quality supported by systems that provide repeatability, precision and traceability. Duoline® Technologies is ISO 9001:2008 certified

Duoline® is a premium internal corrosion resistant lining system for oil and gas steel tubing developed as a high performance, high-value, cost-effective solution to beating the high cost of corrosion and extending the service life of tubulars. Since 1964, more than 80 million feet of Duoline® glass reinforced epoxy lined tubing have been successfully installed worldwide.

For more details contact: David A. Marshall, Duoline® Technologies, 800-345-7423.

E-mail: dmarshall@duoline.com

Websites:

www.duoline.com

www.precision-coatings.com

20-YEAR RELIABILITY FOR DUOLINE® LINING SYSTEMS IN BOTH SWEET AND SOUR WELL APPLICATIONS

2010-12-19T12:04:00.000-08:00

20-Years' Service Life!

DUOLINE-20 HAS RECENTLY BEEN TESTED FOR
20 YEAR LIFE SERVICE IN H2S CONDITIONS.

THE TESTING WAS PERFORMED BY ONE OF EUROPE'S LEADING CORROSION MATERIALS TESTING FACILITIES. THE RESULTS VALIDATED DUOLINE TECHNOLOGIES EPOXY RESIN GLASS REINFORCED LINER'S RESISTANCET TO HARSH CHEMICALS IN TESTING CONDITIONS REPRESENTATIVE OF BOTH SWEET AND SOUR APPLICATIONS.

DUOLINE-20 - A PREMIUM INTERNAL CORROSION RESISTANT LINING SYSTEM FOR PETROLEUM INDUSTRY APPLICATIONS WAS VERIFIED FOR OPTIMUM SERVICE LIFE IN:

* Sweet wells for 20 years
* Sour wells for 20 years

For more information:
www.duoline.com