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Collaborating Authors
SPE International Conference & Workshop on Oilfield Corrosion
Abstract In underbalanced drilling the use of air as an injected gas sets up the potential for oxygen corrosion. Membrane nitrogen with about 5% oxygen eliminates the chance for fire or explosion, but does not solve the corrosion problem. Natural gas or cryogenic nitrogen eliminates the chance for oxygen corrosion, but does not always eliminate the chance of corrosion from other down hole acid gasses (Hydrogen Sulfide, H2S, Carbon Dioxide, and CO2). Any corrosion that occurs while drilling will be forced by some drilling fluid or drilling operational procedure such as KCl fluids, aerated mud, or floating mud cap operations. The objective of this study is to identify some of the practical elements of corrosion encountered with underbalanced drilling and their optimum solution by development of an advisory system based on field cases and expert opinions. This advisory system is intended to be a field guide for the drilling engineer or rig supervisor. Corrosion is a matter of concern to the drilling contractor because of pitting or loss of steel in the drill pipe. The advisory system is developed by proposing a set of guidelines for the optimal practices to minimize corrosion in underbalanced drilling operations. The optimum practices collected from data and experts' opinions, are integrated into a Bayesian Network BN to simulate likely scenarios of its use that will honor efficient practices when dictated by varying certain parameters. These parameters are measuring corrosion, identifying corrosion types, drill pipe and corrosion, treatment methods for H2S corrosion, CO2 sources and treatment, different methods to test for corrosion, general corrosion prevention and treatment, treatment methods for formation water and makeup water, and recommended practices to minimize corrosion in underbalanced drilling operations. To the best of the authors' knowledge, this paper is the first study to develop an advisory system for minimizing corrosion problems. The developed software solutions on corrosion will be demonstrated such as using mechanical means to reduce O2 concentration and inhibitors for pipe coating. Finally, the advisory system list recommendations for all types of underbalanced drilling (flow, aerated, foam and mist) to minimize corrosion problems.
- Well Drilling > Pressure Management > Underbalanced drilling (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
Abstract Solid particle erosion in the oil and natural gas industry can be detrimental to piping and plant equipment, which can lead to production shutdown and other economic losses. Therefore, it is important to be able to detect and quantify the amount of solids present in the piping and plant equipment. This paper presents experimental results obtained using acoustic sand detectors for a broad range of operating conditions at the Tulsa University Sand Management Projects (TUSMP). The effectiveness of sand monitoring in multiphase flow conditions is evaluated and presented. Experimental impingement measurements were performed with acoustic monitors while varying superficial gas and liquid velocities, sand size, and pipe flow orientation. The major focus was to determine the threshold limits for the acoustic sand monitor. Different tests with various velocity combinations to achieve annular, bubble, dispersed-bubble, mist, slug and stratified flow regimes were performed using pipe sizes of 2-inch and 4-inch diameters, and 20 µm, 150 µm and 300 µm sand sizes. The effects of sand size and flow regime on threshold sand rates as sand injection rates change were investigated. The threshold sand rate results for these multiphase flow regimes were determined experimentally and statistical analysis were performed to eliminate the effect of background noise generated when no sand is present in the system. Threshold limits observed for the stratified flow regime was similar and sometimes higher than the ones for annular and slug flows with the slug flow threshold limits being the lowest of all three regimes. Data for other flow regimes like liquid only, bubble and dispersed bubble flows were compared to annular, slug and stratified flow; the highest threshold limit was recorded for liquid only flows closely followed by the limits for bubble flow compared to the other flow types, the smallest threshold limit was recorded for dispersed bubble flow in the horizontal pipe orientation for the flow conditions tested.The threshold sand detection limits for 150 µm and 300 µm sand types are presented and discussed.
The presentation key objective is to show how synergizing the use of corrosion inhibitor and demulsifiers has enhanced the performance and optimized the cost of Oil Field Chemical (OFC) treatment at Safaniya Onshore Arab Heavy wet crude handling facilities. The various steps involved in synergizing the use of oil field chemicals at Safaniya Onshore Arab Heavy wet crude handling facilities have also been discussed. The key performance factors used to assess the overall impact of the process including the total cost of chemical treatment, the effective mitigation of corrosion in the system, the oil in water content in the produced water system, other process parameters like emulsion and foaming tendency were addressed. Synergizing the use of OFC at Safaniya Onshore Arab Heavy wet crude handling facilities has resulted in chemical treatment cost savings of approximately $2.0 MM per year, better treatment of produced water system and improved corrosion mitigation efficiency of 99.6%. 2 SPE 154099
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.35)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- (4 more...)
Abstract Offshore risers are major assets for oil & gas operator as they represent a significant part of the cost of any offshore project and are relied to transport produced fluids. Furthermore, they represent major Health, Safety, or environmental threats to populations or the environment, if any significant leak or rupture occurs. Therefore any company operating hydrocarbon risers is required to implement rigorous external corrosion management strategy. For an offshore riser installation, life cycle Riser Integrity Management is essential at design concept, FEED, detailed design, fabrication/construction, execution, commissioning, and operations to ensure the asset is fit for service throughout its service life. Riser external corrosion management is an important aspect of the overall riser integrity management during operation which includes operation preparation, inspection, maintenance and repair. In-service riser external corrosion inspections are to be planned to identify the actual conditions of risers for the purpose of integrity assessment to ensure structural reliability. The benefit of planning and executing maintenance and inspection activities simultaneously cannot be over emphasized. This paper will describe some specific external localized corrosion issues frequently enencountered in the offshore oil and gas riser systems. The integrity implications and recommendations for addressing these issues both at the concept selection and Front End Engineering Design (FEED) stage as well as during in-service. The paper will also highlight the major benefit of using the correct mix of inspection techiques or tool based on the prior knowledge of the associated corrosion damage mechanisms and the benefit of an optimized preventive and corrective maintenance strategy in the overall life cycle Riser Integrity Management.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract Predictive maintenance (PdM) helps to determine the optimal time and date when repairs should be performed, offering cost savings over routine or preventive maintenance. PdM is frequently used for constant condition monitoring and equipment evaluation. The main goal is, by statistical process control, to determine when future maintenance will be more appropriate according to the structure condition. Our purpose is to introduce a new PdM concept and technique, avoiding corrective maintenance high costs by undertaking an effective painting control. It has been proven efficient on field, when tools are used such as integrity maintenance management software along with 3D modeling. Structure integrity PdM techniques may be applied on critical structures such as offshore structures, port equipment, refineries, bridges or any structure located on aggressive weather conditions. A new painting control method can be found on integrity maintenance management software. This procedure is used to predict painting corrosion rates and optimize maintenance. It consists on simulating painting schemes using 3D models and doing assessments with image analysis tools on visual inspection, such as corroded area pictures taken on the timeline. This predictive maintenance technique affects the traditional procedures; it may require some time investment to adapt to this new practice. The method implies in innumerous benefits since all the corrosion treatment is done before major interventions are needed. Therefore a corrosion coating monitoring means a low-cost maintenance, it extends the structure life integrity and lowers repairs frequency.
Abstract Description of the Material Corrosion-associated biofilms found in oilfield pipelines are complex systems that typically form anaerobically under turbulent flow conditions, consume the metal substrate on which they form, produce hydrogen sulfide, and often have corrosion products or waxes embedded in their extracellular matrices. A model pipeline has been constructed in the laboratory to approximate these conditions. The development of this laboratory capability has enabled the screening of a series of biocides as treatments for corrosion-associated biofilms in a seawater system. Application Corrosion in general is a constant concern in production and transmission systems, and the carbon steel pipelines that carry water, mixed phases, or water-laden hydrocarbons, are especially at risk for microbiologically influenced corrosion (MIC). The presence of water and nutrients encourages the propagation of bacterial communities and the formation of biofilms, especially on internal surfaces of pipelines. Once these biofilms are established they can quickly develop into breeding grounds for pitting corrosion. In order to control MIC, it is essential to have a method, such as properly applying an effective biocide, to control corrosion biofilms. Results, Observations, and Conclusions The benchmarking process identified candidate chemistries that are effective at killing biofilm-associated bacteria in the model pipeline system. Further testing suggested that a periodic slug dose can help to kill and remove biofilm while preventing undesirable increases in planktonic cells and hydrogen sulfide levels. These results and treatment recommendations will be discussed in this paper. Significance of Subject Matter The benchmarking results indicate that corrosion biofilms can be effectively treated with biocides. Guidelines have been established for the effective dosing of these formulations to help control MIC in pipelines, and will be presented herein.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Management > Strategic Planning and Management > Benchmarking and performance indicators (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract One of the most problematic issues facing aging assets and pipelines in the offshore UK oil and gas industry is exposure to increasing levels of H2S. Increasing levels of H2S can occur due to a number of factors. H2S can be generated within pipelines or topsides facilities due to poor microbial control, leading to SRB activity. This can affect the facilities and pipelines themselves, and anything downstream. H2S can also be generated by field souring, where SRB contamination of the reservoir has occurred due to poor microbial control of injection water. Finally, assets that have produced sweet gas over the majority of their lives may become gas deficient, requiring gas import for start up, gas lift and fuel gas purposes. Even though these assets have been exporting sweet gas, the only gas that may be available for import may be sour. In all of these cases, the existing infrastructure may have been constructed for sweet or slightly sour service, and may now face exposure to sour environments beyond the original design criteria, or beyond the materials limits defined by ISO 15156. In such circumstances, or where a new operator is taking over operatorship of older assets, a sour service assessment of the facilities and pipelines is strongly recommended. This publication describes the sour service assessment process. It also describes the justification criteria for continued operation where materials are found to be non compliant, and the remedial actions required where a suitable justification cannot be put in place. It will also discuss the generic findings from assessments performed on a number of assets and pipelines in the UK sector, and examine in detail the assessments performed for the TAQA Bratani assets and pipelines.
Abstract This paper discusses our successful efforts in developing new all oxygen based acid corrosion inhibitors that are biodegradable, non-bioaccumulating and low in toxicity, that meet industry standards for protection of carbon steel oilfield tubing up to 120°C (~250°F). These are environmentally acceptable inhibitors with the appropriate dispersibility and performance characteristics needed for critical applications in environmentally sensitive areas. Matrix acidizing treatments are employed to remove reservoir damage by introducing acidic solutions (usually hydrochloric acid, HCl) into the formation at pressures below those used in fracturing operations. HCl is also used in acid fracturing as an alternative to proppant fracturing. The use of HCl requires that an effective acid corrosion inhibitor be included in the treatment package to protect the well's hardware. Quaternary amines, including pyridine and quinoline quats, are frequently used as the active components in many corrosion inhibitors. While possessing excellent inhibition properties, the compounds are toxic to many forms of sea life, as well as to humans. Quats have been the backbone of the HCl acid corrosion control efforts for many years since they are very effective inhibitors and were often beneficial in improving the compatibility of the inhibitors with the HCl formulations. While oxygen based acid corrosion inhibitors are also in commercial use, they are usually formulated in conjunction with quats. As environmental regulations become more stringent, some compounds are being banned or are listed for substitution. In the United States and Canada, producers and service companies alike are developing product standards to improve their portfolios in an effort to proactively address environmental concerns and to be responsible corporate citizens. Our efforts were focused on developing oxygen-based inhibitors that met or exceeded the current regulations and requirements established by various governments, producers and service companies. The target was to formulate an inhibitor that contained only environmentally acceptable components, and specifically excluding propargyl alcohol, pyridine and quinoline quats, US EPA Priority Pollutants, nonylphenol ethoxylates (NPE), BTEX, methanol, ethylene glycol and ethylene glycol monobutyl ether (EGMBE). Developing an all oxygen-based inhibitor proved to be quite challenging.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (5 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Acidizing (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Corrosion Inhibition Workflow Allows Injection of High-Volume Acid Treatments through Coiled Tubing Strings in Offshore Mexico
Martin, Frederic (Schlumberger) | Miquilena, Emilio (Schlumberger) | Molero, Nestor (Schlumberger) | Acevo, Ana Karina (Schlumberger) | Franco, Ernesto (Schlumberger) | Garcia, Martin Garcia (Petroleos Mexicanos) | Castillo, Marco (Petroleos Mexicanos)
Abstract Since 2003, the main challenge of selective matrix treatments with coiled tubing (CT) has been to manage the severe corrosion rates of CT strings with large acid volumes and long exposure times to hydrochloric acid (HCl), resulting in reduced pipe life. Generally, the average volume required per job is 300 bbl of 15% to 20% HCl, depending on the bottomhole conditions and damage mechanisms; severe material losses of carbon steel coiled tubing string grade 90,000 psi have been regularly measured above 0.20 lb/ft. Our local stimulation team has developed an engineering workflow that consists of several stages and can reduce corrosion rates below 0.05 lb/ft. A laboratory database was built to perform corrosion tests under time and temperature conditions and evaluate available corrosion inhibitors. The database allows the selection of the inhibitor and concentration range for each application. To reinforce the quality control, field preparation of acids is monitored and samples are tested to compare with laboratory design. Finally, measurements of coiled tubing wall thickness give an estimated value of material weight loss. As a result of the implementation of the workflow, average pipe life has been extended from 1,200 to 3,000 bbl of 15% HCl pumped.
- North America > United States (0.69)
- North America > Mexico (0.67)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract During acidizing stimulation or cleanup operations, metal tubulars, downhole tools/valves, surface lines, etc. are exposed to acidic fluids and are prone to corrosion. Because corrosion rates drastically increase in high-temperature wells, controlling corrosion is critical and must be dealt with carefully. In addition, corrosion protection is important for maintaining the integrity and long life of downhole tools installed in a well. Several corrosion inhibitors, such as quaternary ammonium compounds, propargyl alcohol-based compounds, etc., have been effectively used in the industry. However, because of stringent environmental regulations, attention has focused on the development of new corrosion inhibitors that are environmentally benign. Food-grade products that are considered "green" chemicals have significant potential as corrosion inhibitors in the oil and gas industry. In this paper, application of chicory as a corrosion inhibitor for high-temperature and strong-acidic conditions is discussed. Chicory is a perennial bush plant available in many parts of the world. The root of the chicory plant can be roasted and ground for use as a coffee substitute or additive. Chicory is environmentally acceptable and, being of plant origin, is widely recognized as biodegradable in nature. This study shows that chicory can provide corrosion protection for alloys, such as N-80, 13Cr-L80, and 1010 steel, in the presence of either inorganic or organic acids at temperatures up to 250°F (121°C). Considering its good performance, low price, and no toxicity issues, chicory has significant potential for acid corrosion-inhibition applications. The mixing procedure for preparing the blend, experimental setup and test procedure, and laboratory results of high-pressure/high-temperature (HP/HT) corrosion tests are discussed.
- North America > United States (1.00)
- Europe (0.68)
- Research Report > New Finding (0.69)
- Research Report > Experimental Study (0.55)
- Water & Waste Management (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)