GP 43-52_Inspection & Integrity Assesment
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GP 43-52_Inspection & Integrity Assesment

Course Number: INTEGRITY 12054, Spring 2010

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Document No. Applicability Date GP 43-52 Group 29 June 2006 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems GP 43-52 BP GROUP ENGINEERING TECHNICAL PRACTICES 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Foreword This is the first issue of Engineering Technical Practice (ETP) BP GP 43-52. This Guidance on Practice...

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No. Document Applicability Date GP 43-52 Group 29 June 2006 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems GP 43-52 BP GROUP ENGINEERING TECHNICAL PRACTICES 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Foreword This is the first issue of Engineering Technical Practice (ETP) BP GP 43-52. This Guidance on Practice (GP) is newly created and is not based on heritage documents from the merged BP companies. Page 2 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Table of Contents Page Foreword ........................................................................................................................................ 2 Introduction ..................................................................................................................................... 5 1. 2. 3. 4. 5. Scope .................................................................................................................................... 6 Normative references............................................................................................................. 6 Terms and definitions............................................................................................................. 7 Abbreviations ......................................................................................................................... 7 Inspection overview ............................................................................................................... 7 5.1. General....................................................................................................................... 7 5.2. Inspection plan............................................................................................................ 8 5.3. Identification of threats .............................................................................................. 11 5.4. Critical feature sizing................................................................................................. 12 5.5. Inspection frequency................................................................................................. 12 Selection of inspection methods........................................................................................... 13 Structural reliability analysis (SRA) ...................................................................................... 14 Assessment of reported features ......................................................................................... 15 8.1. PDAM ....................................................................................................................... 15 8.2. Use of ILI data .......................................................................................................... 17 Operators’ response to discovering features........................................................................ 18 Pipeline records and data management............................................................................... 19 6. 7. 8. 9. 10. Annex A (Normative) Available assessment methods in PDAM .................................................... 21 Annex B (Normative) Typical feature classification........................................................................ 22 Annex C (Informative) Inspection techniques ................................................................................ 23 C.1. In-line inspection tools ......................................................................................................... 23 C.2. Hydrotesting ........................................................................................................................ 23 C.3. Direct assessment ............................................................................................................... 24 C.4. Onshore pipelines ................................................................................................................ 25 C.4.1. General..................................................................................................................... 25 C.4.2. Major crossings......................................................................................................... 25 C.4.3. Areas of high voltage AC interference....................................................................... 26 C.4.4. Geo-hazards ............................................................................................................. 26 C.4.5. Surveillance for 3rd party damage.............................................................................. 27 C.5. Offshore pipelines ................................................................................................................ 27 C.5.1. Landfall/ surf zone..................................................................................................... 28 C.5.2. Risers ....................................................................................................................... 29 C.5.3. Subsea installations .................................................................................................. 29 Bibliography .................................................................................................................................. 30 Page 3 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems List of Tables Table 1 - Typical onshore pipeline inspection frequency ............................................................... 13 Table 2 - Typical offshore pipeline inspection frequency ............................................................... 13 List of Figures Figure 1 - Pipeline integrity management jigsaw ............................................................................. 8 Figure 2 - Inspection and assessment overview............................................................................ 10 Figure 3 – Assessment of reported features.................................................................................. 16 Page 4 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Introduction Pipeline systems provide a safe and efficient means of transporting a wide range of fluids from water, oil, gas, and petroleum products, to chemicals. They are utilized in all parts of the BP Group and include upstream production flow-lines, export pipelines, chemicals, and refined products pipelines. This document provides guidance to BP Business Units (BUs) and their projects on the requirements for the inspection, testing, and assessment of pipelines. Page 5 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 1. Scope This Engineering Technical Practice has been written for use by the Engineering Authority (EA) and the Pipeline Technical Authority (PTA). It gives guidance on the requirements for inspection and assessment of pipelines as an integral component of the PIMS. The purpose of pipeline inspection is to establish the condition of the pipeline and verify that it is fit for continued operation throughout the life of the system. These are key requirements of GP 43-00 and of the PIMS process detailed in GP 43-49. Inspection and assessment may also be required as part of a due diligence process when assets are either acquired or transferred. The PIMS process requires that components of the pipeline system be inspected on a regular basis. The primary focus of this GP is inspection of pipelines from pig trap to pig trap. As such there are many components of pipeline systems that are not covered by this GP. Inspection of pipeline system components such as tanks, process piping, pressure vessels, rotating machinery, and protective devices can be found in the GP 32 series. 2. Normative references The following normative documents contain requirements that, through reference in this text, constitute requirements of this technical practice. For dated references, subsequent amendments to, or revisions of, any of these publications do not apply. However, parties to agreements based on this technical practice are encouraged to investigate the possibility of applying the most recent editions of the normative documents indicated below. For undated references, the latest edition of the normative document referred to applies. BP GP 06-32 GP 06-36 GP 43-00 GP 43-01 GP 43-10 GP 43-17 GP 43-29 GP 43-49 GP 43-53 GP 43-55 RD 43-521 RD 43-522 Group Integrity Management Standard Guidance on Practice for Cathodic Protection of Onshore Pipelines. Guidance on Practice for Cathodic Protection Maintenance and Monitoring. Guidance on Practice for Pipeline Systems (Overview Document). Guidance on Practice for Principles of Onshore Pipeline Design and Project Execution. Guidance on Practice for Route Data Acquisition and Route Selection for Pipelines. Guidance on Practice for Pipeline Risk Management. Guidance on Practice for Land Acquisition. Guidance on Practice for Pipeline Integrity Management Systems. Guidance on Practice for Pipeline Intervention and Repair. Guidance on Practice for Management of a Pipeline Corridor. The Pipeline Defect Assessment Manual (PDAM), Final Report to the PDAM Joint Industry Project, Penspen Ltd. Pipeline Operators Forum (POF) ‘Specifications and Requirements for Intelligent Pig Inspection of Pipelines’. American Society of Mechanical Engineers (ASME) ASME B31.8S Managing System Integrity of Gas Pipelines. Page 6 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems NACE International (NACE) NACE RP0104 NACE 35100 The Use of Coupons for Cathodic Protection Monitoring Applications. In-Line Non-destructive Inspection of Pipelines, Item No. 24211. 3. Terms and definitions For the purposes of this GP, the following terms and definitions apply: Feature An indication identified by inspection that may affect the integrity of the pipeline system Risk The product of the likelihood of a specific threat or failure scenario occurring and the consequences 4. Abbreviations For the purpose of this GP, the following symbols and abbreviations apply: AUT BoD DA EA ECDA GIS HCA ICDA NDT PIMS PTA ROW UT Automated Ultrasonic Technique Basis of Design Direct Assessment Engineering Authority External Corrosion Direct Assessment Geographical Information System High Consequence Area Internal Corrosion Direct Assessment Non-destructive testing Pipeline Integrity Management System Pipeline Technical Authority Right-of-Way Ultrasonic testing 5. 5.1. Inspection overview General a. This GP shall be read in conjunction with BP Group Policies and Standards and the full suite of Category 43 ETPs. 1. The approach taken shall be consistent with the Group policy document for HSSE and the Group Integrity Management Standard. Page 7 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 2. b. Organisational responsibilities referred to in this document shall be in accordance with GP 43-49. Inspection and assessment of the condition of a pipeline are two key elements of the PIMS, as described in GP 43-49 and illustrated by Figure 1. Figure 1 - Pipeline integrity management jigsaw Audit and Baseline Assessment Training Inspection and Maintenance Engineering and Design MANAGEMENT SYSTEMS Fitness for Service (PDAM) Risk and Reliability Operation Control and Monitoring Repair and Rehabilitation c. If a pipeline is damaged in service, an integrity assessment shall be undertaken to determine the severity of the damage and the required remedial actions to ensure safe continued operation. Planning for periodic inspection and assessment of pipelines shall be undertaken early in the design phase of a project, e.g. Select phase, and not left to the operational phase. During project development, the risk and consequence of failure, the type of event and features that could lead to failure, and the available inspection techniques shall be identified. These factors may directly influence the pipeline system design, e.g. the provision of pig traps, material selection, diameter changes, and the provision of additional protection features. This cannot be achieved without discipline engineers and operations staff. d. e. 5.2. Inspection plan a. An inspection plan shall be established for each pipeline as part of the requirements of PIMS, covering all component parts of the pipeline system. See Figure 2 below. Some components such as tanks, pressure relief systems, or pig traps may be included in Facilities Integrity Management System (FIMS). Whilst all components are captured somewhere it is important that during a review the pipeline is still reviewed as a complete system and that components are not lost between organisational groups. b. The inspection plan shall comply with local regulations and shall address each of the key risks identified in the risk management plan and the critical feature size that could lead to failure. The inspection plan shall focus upon the following key steps: c. Page 8 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 1. 2. 3. 4. d. Inspection (measurement). Assessment of condition. Response (remedial action/ future monitoring or inspection). Review of inspection plan. Inspection scope and frequency shall be based upon the risk assessment which shall consider and evaluate the risks associated with the loss of pipeline integrity in terms of the following consequences: 1. 2. 3. Safety. Environment. BP business and reputation. Guidance in this GP does not replace regulatory requirements affecting the pipeline. e. f. The inspection plan shall adhere to local regulatory requirements. The inspection plan shall be based on the structural design and critical loadings and feature sizes given in the pipeline BoD. If the BoD does not exist or is not adequate to provide sufficient guidance, the necessary design basis and limitations need to be established and specialist advice needs to be sought. New design concepts or the introduction of new materials often introduce a new or different element of risk. If this occurs, an increased level of monitoring is recommended until an operational track record has been established. g. The inspection plan shall include: 1. 2. 3. 4. 5. Objectives and scope of the inspection. Accuracy, reliability, and limits of the inspection techniques. Responsibilities and competencies. Reporting criteria. Frequency of inspection. h. The inspection plan shall be reviewed at appropriate intervals (this should normally be part of the annual PIMS review) with the PTA, noting changes to either the threats to or condition of the pipeline. Changes in either may indicate a need to change the type, scope, or frequency of inspection. i. j. The competency of contractors and people employed to carry out the inspection shall be verified to ensure that they are suitable for each inspection type. Procedures shall be maintained to promptly assess and respond to the condition of each pipeline. These include: 1. 2. Reporting of features that could affect pipeline integrity, ensuring reports are effectively communicated across the organisation. Appropriate actions to prevent harm to people, the environment, business, and reputation. k. A response plan shall be established for each pipeline which sets clear time limits from the discovery of a feature to taking remedial action. In some countries regulations set clear time limits from time of discovery to action Page 9 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems l. Records of each inspection and actions taken shall be maintained and available for review. Timing of the response depends on the nature of the feature and the consequence of failure. In some instances, these may be driven by local regulations. Figure 2 - Inspection and assessment overview INSPECTION NEED INSPECTION SCOPE Routine IM Plan Incident Specific Tech Comm Risks INSPECT Incident Response ASSESS RESULTS BUSINESS VALUE Due Diligence FEEDBACK CONFIRM FIT FOR SERVICE REMEDIAL ACTION REQUIRED Figure 2 illustrates a typical overall flowchart for inspection and assessment with 5 key steps: • Identification of the need for inspection. This could either be a routine inspection as part of the PIMS or a result of an incident (e.g. extreme weather, seismic activity, landslip, or third party damage). It is not possible to conduct a meaningful inspection unless clear guidance is provided on what needs to be inspected and why. Definition of the inspection scope. In the case of the routine inspection, this would be in accordance with the risk based inspection plan drawn up under the PIMS requirements. For incident responses it is specific to the nature of the incident. For due diligence the scope would be that required to understand the technical and commercial exposure in change of asset ownership. Execution of the inspection, using the range of tools and techniques appropriate to the system, its environment, and critical failure modes. Assessment of the results against acceptability criteria (critical feature sizes, allowable spans, etc.) based upon the original pipeline design basis and established within the inspection plan. Confirmation in the case of a routine inspection, that either the system is fit for continued operation or remedial action is required. In some regulated locations this may require certification by an independent authority. • • • • m. For due diligence inspections, the cost of any remedial actions shall be assessed and inputted to an overall business value assessment model for the asset. Additional guidance is available in: • • Section 10 of DNV OS F101, for the inspection of sub-sea pipelines. ASME B31.8S for onshore gas pipelines. Page 10 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems • 5.3. API Std 1160 for liquid pipelines. Identification of threats Typical threats to pipeline integrity are detailed in GP 43-17. Categories that shall be considered include, but are not limited to: a. Time dependent 1. 2. 3. 4. b. 1. 2. c. 1. 2. 3. 4. 5. d. 1. 2. Internal corrosion. External corrosion (including AC corrosion). Stress corrosion cracking (internal or external). Fatigue (e.g. due to pressure cycling or lateral or upheaval bucking) Manufacturing features. Construction features. Third-party damage. Vandalism/sabotage/illegal interference. Operating errors. Extreme weather. Ground movement/geo-hazards. Seal/gland failure. Safety/ protective device malfunction. The nature of the threat also depends on the: • • • • • Materials of construction. Fabrication and installation procedures. Fluid to be transported, including assessment of possible changes over time, e.g. water cut, souring. External environment. Design. Stable Time independent Equipment-related Materials of construction influence the potential threats to be considered e.g. corrosion resistant alloys such as 13% Cr martensitic or 22% Cr duplex stainless steels have internal corrosion resistant properties, but can be vulnerable to external coating failures and hydrogen-induced stress cracking. Fluid type influences the pipeline’s susceptibility to internal corrosion and corrosion fatigue (through pressure cycling). It also affects the type of inspection that is suitable. For example, ILI tools using ultrasonics are more readily applied to liquid filled pipelines than to gas systems, where they can be highly problematic. The pipeline’s physical environment can influence both the nature of the potential threat as well as affecting access for inspection and the feasibility and ease of deployment of inspection techniques. The geometry of the pipeline and the availability of suitable launch/receive facilities determines whether pigging is possible. Page 11 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 5.4. Critical feature sizing a. A written BoD shall be prepared for each pipeline which clearly states the critical sizes of features such as free spans, lateral movements, and metal loss features. Failure may constitute a loss of containment or loss of production capacity due to reduced operating pressure or velocity constraints. b. The critical feature size for various components or segments of the pipeline system shall be identified by consideration of a range of parameters, including the following: 1. 2. 3. 4. Pipe dimensions. Pipe material. Consequences of failure (including identification of high consequence locations). Loadings on pipeline a) b) 5. 6. 7. 8. c. d. Static. Dynamic. Pipe temperature. Fluids in pipeline (corrosivity). External environment (soils or water contacts). Corrosion protection systems. Before carrying out the inspection, a response plan shall be prepared to address the actions to be taken in the event that a critical feature is identified. The response plan shall clearly state the time limits within which action needs to be taken for each feature type. Such a plan significantly reduces the time taken to restore the pipeline to normal operating service conditions. 5.5. Inspection frequency a. The frequency of inspection shall be determined by the risk of failure as described in GP 43-17 and GP 43-49. The ability to inspect a pipeline is important and GP 43-00 places increased emphasis on this for new pipelines. In some parts of the world, local regulations may dictate inspection intervals. The type of inspection carried out depends on the purpose of the inspection. Inspection may be required to prevent an action taking place such as prevention of third party damage or it may depend on the critical feature size to prevent fatigue failure. The frequency of inspection varies for each pipeline and whether the pipeline passes through HCAs (either populated areas or environmentally sensitive areas, for example). Tables 1 and 2 illustrate typical inspection frequencies for a range of inspection techniques applied to onshore and offshore pipelines with notional high and low risks. Page 12 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Table 1 - Typical onshore pipeline inspection frequency METHOD Aerial Survey Vehicle/ Foot Patrol Corrosion Probe Readings In Line Inspection CP Testing River Crossing Survey Geo-Hazard Inspection HIGH RISK Every 2 Weeks Daily Monthly Every 2 Years Monthly Yearly and after Major Events Yearly and after Major Events LOW RISK Monthly Monthly Annual > 5 Years Every 6 Months Every 2 Years and after Major Events Every 2 Years and after Major Events Table 2 - Typical offshore pipeline inspection frequency METHOD Visual Inspection (above Water) Diver Inspection of Splash Zone Corrosion Probe Readings In Line Inspection Sonar Sidescan CP Anode Depletion ROV Inspection Diver Deployed NDE Geo-Hazard Inspection HIGH RISK Daily Yearly Monthly 2 Years 1 Year 3 Years As Required (See Note 1) As Required (See Note 2) As Required (See Note 3) LOW RISK Yearly and after Major events Every 5 Years Annual > 5 Years Every 5 Years 10 Years 5 to 10 Years Not Required Not Required Note 1: After specific incident or anomaly identified by sonar side-scan survey. Note 2: If specific wall or weld feature is identified or suspected. Note 3: If specific active geohazard is identified, or after major events. 6. Selection of inspection methods a. An appropriate inspection method shall be selected for each component of the pipeline system. The PIMS process normally requires the application of more than one inspection method to verify the condition of the pipeline system. ILI is the preferred method for detecting and characterising features that have developed during service. It is preferable to hydrotesting, because the condition along the whole length of the pipeline can be established. ILI may not detect all critical features and it is important that an appropriate tool selection is made. In some instances the technology or equipment may not be available (e.g. crack detection of thick wall multi diameter pipelines). b. c. If ILI is not feasible the design basis should be challenged and if necessary the design concepts should be changed to facilitate inspection. If ILI is the primary method of inspection selected, the selection process shall determine the most appropriate ILI tool for the type of features to be detected. RD 43-522 provides guidance on tool selection and specification. Page 13 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems ILI may have difficulty detecting stress-corrosion cracking with Magnetic Flux Leakage (MFL) tools. If ultrasonic tools are used, the accuracy of results depends on the cleanliness of the pipeline. ILI tools for assessing metal loss cannot be used to establish external condition of the pipeline where earth movements or spanning may be significant. ILI is not substitute for ROW inspection to prevent third party damage. d. If ILI is the primary method of inspection consideration should be given to the inclusion of a spool piece in the pipeline with a number of specially manufactured features so that the performance of the inspection tool and ability to detect critical features can be verified. The feature type, size, orientation and location should be selected to confirm the sensitivity of the inspection tool without acting as a cause of failure. Consideration shall be given to modifying non-piggable pipelines to accept the passage of ILI tools. If ILI cannot be used, hydrostatic testing shall be considered as a means of demonstrating the integrity of the pipeline system and fitness for continued operation. This requires the pipeline to be removed from service which may have a commercial and operational impact. Hydrostatic testing only provides an indication of suitability of the line for pressure containment and is not a substitute for other inspection requirements. It is only valid at the time the test is carried out. g. Direct assessment methods for evaluating external corrosion (ECDA) and internal corrosion (ICDA) as defined in ASME B31.8S shall only be considered if ILI or hydrotesting are not possible. This is because these methods are statistically-based and are, therefore, subject to a greater level of uncertainty than the primary tools such as ILI or hydrotesting. Direct assessment is not a substitute for ROW inspection to prevent third party damage. Further guidance on these techniques and inspections at specific locations is given in GP 06-70. h. An effective record keeping system (e.g. GIS) shall be established for evaluation of inspection and survey data. The pipeline records shall be incorporated into this system. The data for example could include the location of anodes on sub-sea pipelines, combination of other examinations, data from previous in line inspections, etc. e. f. 7. Structural reliability analysis (SRA) a. If direct assessment methods are applied, SRA techniques shall be considered to compliment this technique and improve the confidence level of the pipeline integrity assessment. These techniques are based upon a combination of structural mechanics and probability theory to account for the uncertainties and can be used to predict the probability of pipeline failure. b. If ECDA or ICDA are used in conjunction with SRA and the resulting probability of failure leads to a level of risk that does not satisfy the criteria described in GP 43-17, further data shall be gathered. For example, in the case of ECDA, by excavation of a trial pit (bell-hole), failure probability can be updated using the technique of Bayesian updating. This can be Page 14 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems further refined by an iterative process until an acceptable level of integrity is demonstrated. Structural reliability assessment techniques can be applied in conjunction with most inspection techniques to provide a greater robustness to forecasting pipeline integrity including ILI and DA methodologies; however, in view of the inherent uncertainties associated with DA, they are particularly suited to be used in combination with this. 8. 8.1. Assessment of reported features PDAM a. Reported features shall be assessed using RD 43-521 (PDAM) or a procedure developed specifically for the pipeline based upon PDAM. The pipeline industry has, over a number of years, developed methods for assessing the significance of features in pipelines. PDAM provides an overview of current best practice in pipeline assessment methods. Additional guidance is also given for the assessment of features in pipe fittings. Different levels of assessment are available in PDAM, ranging from simple ‘screening’ methods to sophisticated numerical models. The method to be used depends on the type of feature detected, the pipe material, the loading conditions and the type and quality of the data that is available. A flowchart which provides guidance on the identification, investigation, and assessment of reported features in pipelines is given in Figure 3 (taken from PDAM). Page 15 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Figure 3 – Assessment of reported features Page 16 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems b. Clear time limits shall be established for the assessment and remediation of features following inspection. This may include formalised reporting to regulatory authorities. The feature may have been reported by ILI or during a visual examination. Alternatively, damage may be suspected if routine maintenance or inspection intervals reveal anomalous CP readings, coating anomalies or indications of thirdparty activity in the vicinity of the pipeline. c. Assessment shall be carried out by a recognised competent person who is fully conversant with PDAM and has access to other relevant specialist services in the field of materials engineering, NDT, design, repair, and plant operation. Annex A summarises the available assessment methods in PDAM and when specialist advice should sought, be depending on the type of feature detected and loads imposed on the pipeline. The assessment methods are semi-empirical and PDAM clearly states the limits of applicability of the methods which should not be used for assessing features beyond these limits. The following limitations shall be noted: 1. 2. 3. 4. 5. Methods are generally applicable to pipeline material grades up to API 5L X70. Methods are generally applicable for internal pressure loading; only limited guidance is given for assessing pipelines subject to both internal pressure and external loading. Methods are generally applicable to tough, ductile material. Assessment methods are applicable to parent pipe. Only limited guidance is given to assess features at welds. Corrosion damage can only be assessed for static internal pressure loading. Guidance is not available for pipelines subject to cyclic internal pressure loading. d. e. f. 8.2. The results of the assessment shall be independently checked and formally documented. Use of ILI data a. The uncertainties associated with ILI data shall be taken into consideration when undertaking assessments of reported features. Reliable predictions of the remaining strength of damaged pipelines depend on the assumptions made when assessing reported features. Interpretation of ILI data, in most cases, requires careful judgment and scrutiny before assessments are carried out. It is important to determine how inspection data has been supplied as this can vary from one ILI vendor to another. Inspection data may be supplied in ‘boxed’ form where each individual feature has a box drawn around it. Alternatively, the inspection data may be supplied in clustered form, where individual boxes located in close proximity to one another are considered as a single feature. b. The method of reporting ILI data, including use of the interaction criterion for clustering features, shall be agreed with the ILI vendor and in accordance with RD 43-522. When sizing and locating features, three types of uncertainties can arise: • • • c. Threshold (detection) levels, also referred to as the probability of detection. Sizing accuracy or inspection tolerance. Data interpretation and feature identification. The uncertainties shall be quantified and a clear explanation shall be given of how different types of feature are identified. Data can be obtained from inspection vendors and from NACE Publication 35100. Page 17 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 9. Operators’ response to discovering features a. An emergency response procedure shall be prepared for each pipeline specifying the response to incidents or features reported by third parties or through formal inspections, including target response times. It is important that the response following discovery of a feature is appropriate and is carried out in a reasonable time frame. In some countries this is dictated by regulations. b. To avoid delays in assessment, a procedure for the assessment of reported features should be established for each pipeline system, including critical feature sizes and intervention strategies. An initial assessment of the pipeline condition shall be made as soon as a feature is reported. Features shall be categorised into one of three categories, depending on the reported severity of the damage: 1. 2. 3. Severe damage. Significant damage. Superficial damage. Severe damage poses an immediate threat to the integrity of the pipeline (e.g. a feature with a calculated burst pressure lower than MAOP). Significant damage has no immediate impact on the integrity of the pipeline, but impacts the long term integrity due to potential feature growth and is therefore unsafe to be left for the longer term unless supported by expert assessment. Superficial damage has no impact on the immediate or long term integrity of the pipeline. e. f. g. If the classification of defects is not determined by regulations, classification shall be in accordance with Annex B. Steps shall be taken to ensure that the pipeline pressure cannot rise above the pressure at the time the pipeline was inspected or feature reported. Risks associated with working on live pipelines containing reported features shall be addressed. Closure of an emergency shutdown valve (ESDV) at a plant may cause pressures in the line to equalise and rise above the pressure at the time of damage, leading to loss of containment. h. If severe damage is reported, temporary measures to prevent failure shall be implemented immediately. Suitable temporary measures are: 1. 2. Reduction in operating pressure. Installation of temporary leak clamp. The extent to which the pressure is reduced depends on the operating stress levels and the nature of feature reported. Further pressure reduction may also be required during an on site inspection to reduce the risk to inspection personnel, the public, and the environment. This may be caused by re-categorization of the feature, e.g. the discovery of cracks in combination with a reported dent. i. A more detailed examination and assessment of features classified as severe shall be carried out within 30 days. c. d. Page 18 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems j. Features shall be re-categorised as severe, significant, or superficial based on the results of the assessment. The decision is left to the PTA whether to repair immediately or to refer the feature for further expert assessment (or further inspection). This decision depends on relative costs and logistical constraints. If the feature was reported by ILI, the pipeline may need to be excavated and visually inspected to verify the type of damage (i.e. corrosion, dent, gouge, etc.) and to take additional measurements. Working in the vicinity of a damaged pipeline is a potentially hazardous operation and the inspection activity itself (e.g. removal of corrosion products from the pipeline) may cause failure of the pipeline. Pipelines operating at a high level of stress generally have smaller acceptable feature sizes and failure may result in a rupture rather than a localised leak. k. For severe and significant features, permanent measures to prevent failure shall be implemented within 6 months of initial discovery of the feature. Suitable permanent measures are: 1. 2. 3. Permanent repair. Pipeline derating (permanent reduction in MAOP). Decommissioning. l. Superficial features do not require repair, but they shall be monitored in future inspections as they may be subject to time dependent growth. If the feature has been exposed for inspection and assessment, any coating damage should be repaired before reinstatement. m. The pipeline shall not be returned to normal service until a formal assessment has been completed. This assessment shall be reviewed by the PTA. The formal assessment may conclude that repair work is required before the pipeline can be returned to service. n. o. Operating pressure restrictions shall remain in place until repair has been completed. Repair methods shall be selected in accordance with GP 43-53, depending on the type of damage and loading to the pipeline. The suitability of the method for anticipated loading conditions shall be considered including any potential dynamic effects such as vibration or fatigue. The Emergency Response Plan shall include clear lines of communication throughout the inspection, assessment, and repair process. p. 10. Pipeline records and data management a. Records shall be made of inspections, assessment of features, and follow up actions in accordance with the PIMS process as described in GP 43-49. Systems used to capture the data depend upon the local practices; however, for ease of use, computer-based systems, such the use of a GIS interface, are preferred to enable consistent retrieval and analysis of the data. b. c. In addition, consideration should be given to the use of an action tracking system to monitor outstanding activities to closure. As a minimum, the following information shall be recorded for each inspection: 1. 2. Date, time, and location of inspection. Inspection method and vendor/specialist operator. Page 19 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 3. 4. 5. 6. Inspection results. Analysis of any reported features. Remedial action taken or follow up required. Review approvals/comments by EA or PTA. There have been many instances in which damage has occurred and the pipeline has been repaired, but inadequate or no records were maintained of the original feature or the repairs being carried out. During subsequent inspections, it has been difficult to establish whether action needs to be taken. Page 20 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Annex A (Normative) Available assessment methods in PDAM Feature and Loading Type Intact pipe Corrosion Gouges Plain dents Kinked dents Smooth dents on welds Smooth dents and gouges Smooth dents and other types of feature Manufacturing features in the pipe body Girth weld features Seam weld features Cracking Environmental cracking Notes: 1. Red denotes cases where specialist assistance is required. 2. Yellow denotes cases where specialist assistance may be required. Internal Pressure (static) YES YES YES YES NO NO YES YES YES YES YES YES YES Internal Pressure (cyclic) YES YES YES YES NO YES YES YES YES YES YES YES YES External Pressure YES NO NO NO NO NO NO NO NO NO NO NO NO Axial Force YES YES YES NO NO NO NO NO YES YES YES YES YES Bending Moment YES YES YES NO NO NO NO NO YES YES YES YES YES Combined Loading YES YES YES NO NO NO NO NO YE YES YES YES YES Page 21 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Annex B (Normative) Typical feature classification Feature Category Severe Feature Types Metal loss with calculated burst pressure < MAOP Metal loss with depth > 80% nominal wall thickness Top-of-line dents with depth > 6%D Top-of-line dents with metal loss or cracking Crack like features with calculated burst pressure < 110% MAOP Crack like features with depth > 50% nominal wall thickness Significant Metal loss with calculated burst pressure < 125% MAOP Metal loss with depth > 50% nominal wall thickness when located at foreign pipeline crossings or on welds Gouge with depth > 40% nominal wall thickness Top-of-line dents with depth > 2%D Bottom-of-line dents with depth > 6%D Bottom-of-line dents with metal loss or cracking Dent with depth >2%D located at a girth or seam weld Ovality > 6%D Crack like features with depth > 40% nominal wall thickness All confirmed cracks Top-of-line dents are located in the upper two-thirds of the pipe between 8 o’clock and 4 o’clock. Bottom of line dents are located in the lower third of the pipe between 4 and 8 o’clock. Page 22 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Annex C (Informative) Inspection techniques C.1. In-line inspection tools a. ILI tools, often called ‘intelligent’ or ‘smart’ pigs, are devices designed to inspect the condition of the pipeline wall without disrupting the operation of the pipeline. Different inline inspection technologies are available for the detection and sizing of different kinds of damage (e.g. corrosion, cracking, etc.). RD 43-522 provides useful guidance in this area. An in-line tool can only detect the condition of a pipeline at the time the pig passes through the pipe and is, therefore, not suited to the detection or mitigation of random events such as third party damage. ILI can identify metal loss that has occurred as a result of mechanical damage. An overview of the types of ILI tools, their capabilities in detecting the variety of features, accuracy of detection, feature characterization, pipeline operational issues, considerations for the different types of fluid being conveyed, procedures to assess the suitability of pigging a pipeline, etc. can be found in NACE Publication 35100. ILI tools currently exist for detection of: 1. 2. 3. e. Pipe deformation, such as dents, wrinkles, or ovality. Volumetric metal loss, such as areas of corrosion (both internal and/or external pipe surface) or mechanical damage to the line. Cracking, particularly stress corrosion cracking and some forms of fatigue cracking. b. c. d. In-line inspection technology is constantly evolving and the only reliable way to determine the state of the art is to keep in touch with inspection vendors, other operators, and organisations such as the Pipeline Research Council International, Inc. (PRCI). C.2. Hydrotesting a. Hydro-testing shall only be used to revalidate a pipeline where alternative methods using ILI have been considered and rejected. Hydrostatic testing of a pipeline is a major operation and needs careful planning. GP 43-46 is a useful document for testing guidance. b. Testing procedures, including identification of test pressures, shall make due reference to the original procedures developed during the design and construction of the pipeline system. A specialist hydrostatic test contractor shall be utilised, using strict approved procedures, taking due consideration of key factors including, but not limited to: 1. 2. 3. 4. 5. 6. 7. An assessment in accordance with BP policy ‘getting Health, Safety, Security, and Environment right’ (gHSSEr). Pipeline Maximum Allowable Operating Pressure (MAOP) and design pressure. Pipeline profile. Special sections (road/rail/river crossings). HCA (proximity of public to pipeline). Test temperature (particularly arctic or desert extremes). Water availability and composition (particularly arctic or desert). Page 23 of 30 c. 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 8. 9. Water salinity (offshore). Chemical treatments. 11. Environmentally safe disposal of test water. C.3. Direct assessment DA methods for mitigating against the threat of internal and external corrosion on buried, ferrous onshore pipelines are viable alternatives to ILI and hydrostatic testing in situations where such approaches are either too costly or operationally unsuitable. a. While the methods used may be familiar (use of above ground surveys, for example), it is important to recognise that all four steps in the ECDA process shall be employed. These are: 1. 2. 3. 4. b. c. Pre-assessment. Indirect inspections. Direct examinations. Post assessment. The process is described in detail in NACE RP0502. A particular limitation associated with ECDA is a lack of consideration of the uncertainties associated with the techniques themselves. A similar suite of documents covering ICDA is in the final stages of development by NACE. These are: 1. 2. 3. d. Internal Corrosion Direct Assessment on Dry Gas Pipeline Systems (NACE RP0104). Internal Corrosion Direct Assessment on Wet Gas Pipeline Systems. Internal Corrosion Direct Assessment on Liquid Pipeline Systems. In the dry gas standard, ICDA is described as a four-stage process similar to the ECDA approach. The concept is to predict areas of water accumulation by hydraulic modelling. Detailed examination of the first few areas of water accumulation would then allow the condition of the remaining length of pipe to be forecast by extrapolation/ interpolation. If the locations most likely to accumulate water have not corroded, other downstream locations, which potentially could accumulate water, may be considered free from corrosion. If extensive corrosion is found at many locations, then ICDA is considered inappropriate and other integrity assessment techniques are needed. Techniques used in DA are described in more detail in the GP 06-36. These techniques are continually developing and there is greater interest in establishing the condition of nonpiggable pipelines. 1. Close Interval Potential Survey (CIPS) - This technique involves the measurement of pipe-to-soil potentials at short intervals along a section of pipeline and identifies areas of CP interference or current drainage to/from other structures along with areas of coating failure. Direct Current Voltage Gradient (DCVG) Survey - This technique involves measurement of the DC pipe-to-soil voltage gradient and determines the direction and magnitude of current flow in the soil. It is particularly useful for identifying coating holidays (areas of coating damage and potentially low CP protection) in complex piping systems. e. 2. Page 24 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 3. Electromagnetic Techniques (e.g. Pearson Surveys) - This well established technique is most effective for identifying coating failures in buried pipelines using audio frequency AC induced current. Continuous Soil Resistivity Survey - This technique is an important element in the CP engineer’s toolkit for assessment of the vulnerability of a buried pipeline to corrosion. Typically a 4-pin spot measurement technique is used; however, if continuous measurement is required, then electromagnetic techniques may be employed measuring soil conductivity. Long-Range Guided Wave Ultrasonic Technology (LRGWUT) a.) This recently developed technology employs low frequency ultrasonic waves to inspect 100% of the pipe wall for lengths of typically up to 30 m (100 ft in either direction from a single set-up point. This technique is considered particularly useful for pipeline sections with limited access, such as road, river, or utility crossings. 4. 5. b.) This technique has limited success on pipelines that are well coated or if there are numerous flanges or clamps. 6. Automated Ultrasonics (e.g. Time of Flight Diffraction (TOFD) K-Scan or Phased Array) a.) These techniques are considered to offer enhanced reliability and repeatability in comparison to well proven manual technique and are particularly suited to inspection of pipeline welds during manufacture and pipeline construction. Data analysis capability is enhanced with the capability of AUT to be integrated with computers. b.) TOFD is a reliable technique involving a rapid single-pass weld inspection and offers a direct, safer, and more rapid alternative to radiography. 7. Automated Corrosion Mapping - This is an analytical tool which can be used in conjunction with AUT to provide corrosion profiles which can be used in the assessment of features. C.4. C.4.1. Onshore pipelines General a. b. c. The techniques that follow may be used independently or supplementary to ILI technology. Inspection of crossings shall form an integral component of the overall inspection plan. These are supplementary to those specifically described under DA. Inspection frequency shall be determined by the risk assessment and any local regulatory requirements. C.4.2. Major crossings a. Selection of specific inspection techniques which may be applied for inspection of major road, river, or rail crossings depends upon a number of factors including: 1. 2. 3. b. 1. Accessibility. Criticality of Area (e.g. whether HCA). Specific crossing design configuration. Above ground or aerial crossings. Such crossings could cover a range of designs including: Page 25 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems 2. 3. 4. Open cut buried crossings. Dredged crossings. Bored crossings with or without sleeves a.) c.) Thrust. Horizontal directional drill (HDD). b.) Auger. 5. c. Tunnel crossings, dry or wet. If ready access is available in a dry environment such as an aboveground, aerial, or dry tunnel crossing, allowing safe personnel access using appropriate safety and work permit procedures, then visual and/or direct assessment techniques may be applied. For wet crossings such as tunnel or dredged river (or other waterway) crossings, diver inspection may be considered. Diver inspection can include both visual/ video techniques for record of the inspection and a range of diver deployable NDT techniques including UT. For bored crossings with sleeves, an important component of the inspection plan is the determination of the CP operation through the sleeved section. This can be done by using direct potential CP testing between the sleeve (casing) and the pipe. d. e. C.4.3. Areas of high voltage AC interference a. Specific inspection techniques shall be considered in areas where High Voltage AC transmission cables share the ROW with the pipeline. Applicable survey/ inspection techniques shall ensure the integrity of the pipeline and its CP system are maintained. The key requirement is to ensure that induced voltage or fault current is minimised to an acceptable level (see GP 06-32). It is also assumed that appropriate AC mitigation measures such as zinc ribbon or distributed anodes or spiral ground mats are in place as a component part of the CP system design and that a key element of the inspection is to ensure that they are correctly functioning by measurement of AC pipe-to-ground voltages. This work shall be carried out by an appropriately qualified CP engineer qualified to NACE requirements or equivalent. b. c. C.4.4. Geo-hazards a. During the design and survey phase of the pipeline route corridor development for new pipelines, segments of the pipeline containing geo-hazards which could represent a threat to the system integrity shall be avoided wherever possible (references GP 43-10 and GP 43-01). Any residual unavoidable hazards shall be clearly identified and managed in accordance with the PIMS requirements and as a component part of the Risk Management process (reference GP 43-17). For existing pipelines or acquisitions, these areas shall be identified as part of the Risk Assessment process. During development of the inspection plan, due account shall be taken of these areas and the contributing factors to the threat to pipeline integrity and appropriate priority given to identified high risk areas. An example of this would be an area with geological structure prone to landslip, where heavy rainfall could increase the risk of failure. In this case, regular inspection of these areas, particularly after significant rainfall, should be considered. Another example would be in a desert area where mobile dunes could present a significant threat to overloading or exposing the pipeline. In this instance, periodic inspection is required to monitor sand build-up or scouring around the pipeline. The frequency of such inspections could be determined by monitoring the rate of b. Page 26 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems build-up or scour over time. A similar scenario applies for submarine pipelines in seabed areas with mobile sand waves and scour prone areas, particularly with high bottom currents. Locations of unstable soils in seismic areas are a further case where periodic inspections, particularly after significant seismic activity, would be warranted. Other potential geo-hazards could include hydro-technical hazards such as: • • • c. River bed scour. Bank or cliff erosion. Channel degradation. Arctic permafrost presents particular hazards to pipelines including ground movement (frost heave) and instability during intermittent thawing. The inspection plan needs to account for these aspects and any associated access constraints (e.g. some areas may only be accessible via ice roads which could be impassable in the spring and summer months). C.4.5. Surveillance for 3rd party damage a. This activity forms a critical element for segments of pipelines passing through areas of high activity such as: 1. 2. 3. 4. b. Onshore pipelines in industrial or urban development areas. Onshore pipelines in areas of arable farmland where site drainage activities are ongoing. Offshore pipelines in areas of high fishing activities. Offshore pipelines in areas of high activity such as around platform or drill rig areas or ongoing construction. Critical areas shall be identified during the risk assessment (reference GP 43-17) and the land acquisition process (reference GP 43-29). Specific focus shall be given to prioritizing inspection activities for these areas during the development of the inspection plan. GP 43-55 provides guidance on ROW management and surveillance methods. Tracking systems shall be employed to monitor potential encroachment on the pipeline ROW and liaison maintained with the 3rd parties involved to ensure all necessary notifications are given. These systems can be either computer-based such as a GIS or map-based system, or based upon hardcopy records kept updated after each inspection. c. d. C.5. C.5.1. Offshore pipelines General a. A range of techniques are available for the inspection of offshore pipelines and the following shall be considered when developing the inspection plan for such a system: 1. Towed fish, such as side-scan sonar. This method allows a pipeline route corridor to be surveyed relatively quickly to identify critical areas for further investigation which include: • • • • Unsupported sections of pipeline (free spans). Anchor scours. Bottom trawling scars. Debris or dropped objects. Page 27 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems • • Pipeline or trench discontinuities Lateral or upheaval buckles related to thermal expansion. This data can be gathered and plotted in near real time and critical areas for ROV or diver intervention (depending upon water depth limitations) can be identified. 2. Remote operated vehicle (ROV) with: a.) c.) Video cameras. Pipe tracker (Magnetometer). b.) Trench profiler (scanning sonar). d.) Other specialist tools as required for: - Coating removal. - Pipe cleaning. - CP measurement. - UT. - Pig tracking. The ROV is the primary tool for detailed investigation and in many cases for repair and is almost always used in depths where divers can not be deployed. The modern subsea ROV is a sophisticated tool; and, with the specialist equipment readily available, can perform most of the required tasks for sub-sea pipeline inspection (as well as construction, repair and support for well operation and work-over). ROVs can be tethered (with umbilical to mother-ship) or free swimming. These tasks include: • • • • • • • • Visual survey. Trench profile and burial depth. Pipeline and feature measurement including 3D photogram metric techniques. CP measurement. Coating inspection. Coating removal and cleaning. Wall thickness measurement. Inspection pig tracking. An Autonomous underwater vehicle (AUV) can be used as an alternative to ROV for survey activities. Side-scan sonar survey using AUVs has been very successfully carried out on the BP King flowlines in the Gulf of Mexico and more sophisticated AUVs with pipe tracking capabilities for more detailed survey & inspection are in development and have been trialled in the North Sea. Further alternatives include the manned submersible (free swimming) or the One Atmosphere Bell (OMB) which is used less frequently due to advances in recent ROV technology. C.5.2. Landfall/ surf zone a. Periodic supplementary inspections shall be considered, particularly in areas of high scour or in high risk areas close to habitation or environmentally sensitive areas. For pipelines which can be fully inspected using ILI techniques through these zones, this activity would most likely be a part of a follow-up activity to verify anomalies detected by ILI or in response to suspected 3rd party activity or interference damage in this area. b. In submerged sections, divers may need to be deployed to carry out visual inspection or NDT as required. Page 28 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems C.5.3. Risers a. Supplementary inspection of rigid steel marine risers through critical areas such as the splash zone, where a high risk of interference damage or external corrosion damage exists, shall be carried out as a key element of the offshore pipeline inspection. The submerged or “wet” components in this area shall be inspected by divers with due account of weather conditions and other activities around the offshore installation. Techniques employed may include visual inspection and NDT. Integrity of riser clamps may also be inspected using similar techniques. For deepwater developments where either rigid steel catenary or flexible composite risers are installed, Integrity Management technologies may not be suitable for application and alternative methods of assessing the system integrity shall be considered. These may include visual inspection by ROV or hydrostatic testing. Proprietary NDT techniques are available for the inspection of flexible risers, e.g. for fracture of armour wires. b. C.5.4. Subsea installations a. Subsea installations designed to pipeline codes and in accordance with the pipeline system definition given in GP 43-00 can include: 1. 2. 3. 4. b. Subsea valves (SSVs). Subsea isolation valves (SSIVs). Pipeline end manifolds (PLEM). Production and injection manifolds. These components, including associated spool pieces or flexible jumpers, may not be easily inspected by ILI techniques and alternative methods of assessing the system integrity shall be considered. These may include visual inspection by ROV or hydrostatic testing. Specialist advice shall always be sought. Page 29 of 30 29 June 2006 GP 43-52 Guidance on Practice for Inspection and Integrity Assessment of Pipeline Systems Bibliography A significant number of industry standards and codes of practice have been or are in the process of being developed that relate to pipeline integrity and inspection. Some of the more significant documents are referred to here. BP GP 06-70 GP 43-00 GP 43-06 GP 43-46 Guidance on Practice for Corrosion Monitoring. Guidance on Practice for Pipeline Systems (Overview Document). Guidance on Practice for Responsibilities of an Operator. Guidance on Practice for Pipeline Pressure Testing and Precommissioning. American Petroleum Institute (API) API Std 1160 Managing System Integrity for Hazardous Liquid Pipelines. Det Norske Veritas (DNV) DNV OS-F101 Submarine Pipeline Systems. NACE International (NACE) NACE RP0502 Pipeline External Corrosion Direct Assessment Methodology. Page 30 of 30

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Many businesses lease substantial portions of the property and equipment they use as an alternative to ownership, because leasing provides some financial, operating, and risk advantages over ownership. Leasing allows for 100% financing, protection against
UPenn - ACCT - 621
UPenn - ACCT - 621
Accounting 621 Liability and Equity Valuation Spring 2010 Quiz # 11. Murphy Company issues 6,000 shares of its $5 par value common stock having a market value of $25 per share and 9,000 shares of its $15 par value preferred stock having a market value of
Ohio - STAT - 641
STATISTICS 641, WINTER 2006 MIDTERM EXAM 1 (In class, open book, two crib sheets) Name_ Instructions: You may use your textbook, two sheets of paper with formulas, and a calculator, but not your notes or other reference material. Please write your answer
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #08Deadline: 3:00 p.m., Monday, 10/5/09 LATE WORK WILL NOT BE ACCEPTE
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #03Deadline: 3:00 p.m., Thursday, 9/10/09 LATE WORK WILL NOT BE ACCEP
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #04Deadline: 3:00 p.m., Monday, 9/14/09 LATE WORK WILL NOT BE ACCEPTE
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #05Deadline: 3:00 p.m., Thursday, 9/17/09 LATE WORK WILL NOT BE ACCEP
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #06Deadline: 3:00 p.m., Monday, 9/21/09 LATE WORK WILL NOT BE ACCEPTE
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #07Deadline: 3:00 p.m., Thursday, 10/1/09 LATE WORK WILL NOT BE ACCEP
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #09Deadline: 3:00 p.m., Thursday, 10/8/09 LATE WORK WILL NOT BE ACCEP
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #11Deadline: 3:00 p.m., Thursday, 10/15/09 LATE WORK WILL NOT BE ACCE
University of Texas - CH - CH 310M
MWF 9:00 Section Bocknack CH 310M/318M Fall 2009Please submit to the correct slot in the collection box outside WEL 2.212! Last Name: First Name:UTEID:Score:Graded Homework Problem #12Deadline: 3:00 p.m., Monday, 10/19/09 LATE WORK WILL NOT BE ACCEPT