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Answer: Reports Will Not Generate

Create a backup (BACKPAC file) on the old computer using SQL Server management Studio (SSMS)

Step 1:

Download SQL Server management Studio (SSMS) Download SSMS

Step 2:

1. Open SSMS

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2. The window below will open

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3. Connect to the desired SQL Server instance. In the ‘Object Explorer’ pane, right-click on the name of the desired database

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4. Click on connect icon then “Connect to server” window will launch

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 5. Fill the details and click connect

a.     Server Name :  .\HUBSERVER

b.     Authentication: SQL Server Authentication

c.      Login : sa

d.     Password :HUB@2018

6. Expand database node and right click on “UPDM_Test_1”

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7. In the context menu, we select ‘Tasks’ and then ‘Export Data-tier Application’.

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This launches an introduction page. This introduction page defines the summary and steps for this wizard. :

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8. Click on Next button and then “Export settings” window will show then provide a location to store the backup file then click next

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9. Click Finish on the summary window

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10.  The Progress window below will be displayed

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11.  It will take some time to complete the operation.

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12.  Backup is done, click the close button

Step 2 Import database backup file

1. Open installation path on new computer/laptop where you want to move the data to which is shown below 

C:\TechnicalToolBoxes\HUB\HubService\App_Data

2. Rename the old database file (HUB.bacpac) with a different name like :

 OLD_ HUB.bacpac

3. Then paste here the HUB.bacpac file form old computer to opened folder

C:\TechnicalToolBoxes\HUB\HubService\App_Data

4. Delete the new database that has created on new machine

5. Open command prompt and run the following commands

a.      sqlcmd -S .\HUBSERVER -U sa -P HUB@2018

b.     GO

c.      USE master;

d.     GOdrop database UPDM_TEST_1

e.      GO 

6. Now open the folder 

C:\TechnicalToolBoxes\HUB

And run the HUB.bat file as an administrator

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Today, casings are used primarily on railroads and specific highways such as toll roads.  The casing like the carrier pipe must be designed to withstand concentrated loads, loading, stresses, and must comply with minimum Federal Safety Standards.  Therefore, a cased crossing must be able take the superimposed loads, not the carrier pipe.  A casing is designed to protect the carrier pipe against strain and external loading.

Example, this is one of the reasons why a casing needs to be at least 6” greater in diameter than the carrier pipe.  Otherwise, the pipeline and casing can metallically short  in the middle or ends.  Using a 4” diameter difference can result in metal-to-metal contact of the carrier pipe and casing touching each other permanently or intermittently based on the loads.  Electrical and mechanical isolation between the carrier pipe and casing must be taken to minimize the likelihood to reduce the risk of corrosion and stress issues.

There are other issues with casings such a thinner wall thickness than the carrier pipe, spacers, end seals, etc.

• Carrier pipe should conform to ASME B31.8

• Casing pipe should be a minimum of two nominal pipe sizes than the carrier pipe whereas this can be a problem when casing is greater than 50 feet.

• Consideration should be given for 3 pipe diameters or 6 inches  to avoid installation issues such as:

  • Spacers

  • End Seals

  • Thickness of Coating Layers

  • Insertion of Carrier Pipe through Casing Pipe

  • Heavy Wall Thickness to reduce the Internal Diameter of the Casing Pipe

Below is a typical schematic of Cased Crossing with a Carrier Pipe:

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A newly constructed pipeline trench width is typically excavated to a minimum width of 305 mm (12 inches) greater than the outside diameter of the pipe.

Trench Width is based on many factors:

• Compaction of the soil

• Type of Soil

• Moisture Content of Soil

• Uniform Support Underneath Pipeline i.e., Bedding

• Depth of Cover (DOC)

• Years pipeline has been in service

• Overbends and Sags

• Horizontal Bends – Point of Intersections (PIs)

Note: There are rules of thumb that most US pipeline operators use for determining trench width regarding Wheel Load Analysis and other Crossing applications.

• Newly installed pipe trench less than 5 years - original trench width at bottom

• 305 mm (12 inches) each side of the outside diameter of the pipeline

• Compacted backfill after 5 years - diameter plus 100 mm (4 inches)

• Bored pipelines - diameter plus 50 mm (2 inches)

Technical Toolboxes does not show a factor for steel plating for the following concerns.

• Steel plates are flexible and can slide around when construction equipment is driven over them.

• Ends of steel plates can turn up from equipment.

• There is no independent testing organization that has validated them to date.

• ASME, API, PRCI does not have any specific information on them.

Due to the complexities and geometries of each blowdown piping system, recommending which method is better is difficult. These calculations can require dynamic calculations which are not provided in this AGA paper. It is impossible to generalize these conditions.

The document below provides more detail on the subject.

Most chemical explosives have close to the same energy release per unit weight (W_e). If the explosive being used in a blasting situation is not known, the prediction equations can be used substituting a “typical” value for (W_e).

 Average energy release values for several commercial explosives are shown in the table 1 below.

Table 1 – Weight (W_e)

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The quantity n is a measure of the relative energy ratio among the explosives. Using the energy release of ANFO (94/6) as the base, all explosive energies are normalized to determine the value of n.

N = 1.0 for ANFO

 Thus, ‘for ANFO (94/6), n equals 1.00. Those explosives more energetic have a value of n greater than 1.00 and those less energetic have a value of n less than 1.00. 

A list of equivalent energy release ratios is shown in table 2 below. It should be noted that Dyno Nobel is the primary manufacturer of most explosives in the Western World countries including older names brands that still may exist today.  The Chinese make up the remainder for Eastern World countries.

  Table 2 Equivalent Release Ratio (n)

                         Explosive                                                 n

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Using a Dyno Nobel  Unimax Specification Sheet as shown below, the following Relative Weight Strength can be used to simulate (n) where the above values are not shown.

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Barnes layer data are set up to represent the bulk soil multiple layers for the pipe/corrosive layer, deep/apparent layer (steady state and inductive fault), and conductive/surface layer (conductive fault).  Other considerations include:

• Where soil resistivity are not deep and change i.e., from deep tower footing grounds compared to the shallower pipeline trench, faults may stress the coating.

  • Where these conditions exist, running multiple scenarios at the fault tower(s) are needed for to assess for various depths. 

• Example, using the Barnes Layer in areas where there are deep HDD crossings.  Adjustment to the calculations may be needed to accommodate these depths for more accurate assessment of these layers.

• In HDD crossings, it should be noted that drilling muds contain bentonite clays that have extremely low resistivity values in the range of 100 ohm-cm.  The soil resistivity equipment may, or in most cases may not detect this narrow layer of the drilling muds around the pipe.

  • If the backfill is typical soils, the drilling muds will migrate into the soil after several years.

  • If the backfill is in granite or similar rock, the muds may remain in place for many years.

• Deep Layer (Apparent)

This layer is used to get the most accurate results with a minimum of a 100-foot depth or 30.5  meters.  This layer is used to assess Inductive Faults and Steady State inductive voltages. 

Note:  It has been reported that many practitioners use the common CP type soil resistivity meter readings with the calibrated 5’ intervals wiring that is limited to 20’ that matches the 20’ deep ground rods on towers.  These data may be useful where resistivity readings are low (<1000 ohm-cm) and there are slight changes in other layers.

•  Pipe Layer (Barnes/Corrosive)

This layer should always be around the depth of the pipeline.  Typical depths run from 3 to 6 feet or 1 to 2 meters except for HDD crossings.  It is also used to calculate the current density of amps/m2.

• Conductive Resistivity Layer (Surface)

This layer should always be the top surface layer.  Typical depths run from surface to 10 feet or 3 meters.  It used to calculate conductive faults, step/touch potentials and surface potentials or ground potential rise.

Note:  Barnes Layers - Below is a schematic of these three (3) major layers to consider bulk and specific layer resistivity.  Any of these layers can be varied in depth based on the geo layering and resistivity layers related to pipeline depth. 

NACE/AMPP - Excel Spreadsheet(s) are typically used to calculate these multiple layers. 

Schematic of Barnes Multi-Layers Soil Resistivity for AC Modeling and Mitigation

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Barnes layer data are set up to represent the bulk soil multiple layers for the pipe/corrosive layer, deep/apparent layer (steady state and inductive fault), and conductive/surface layer (conductive fault).  Other considerations include:

• Where soil resistivity are not deep and change i.e., from deep tower footing grounds compared to the shallower pipeline trench, faults may stress the coating.

  • Where these conditions exist, running multiple scenarios at the fault tower(s) are needed for to assess for various depths. 

• Example, using the Barnes Layer in areas where there are deep HDD crossings.  Adjustment to the calculations may be needed to accommodate these depths for more accurate assessment of these layers.

• In HDD crossings, it should be noted that drilling muds contain bentonite clays that have extremely low resistivity values in the range of 100 ohm-cm.  The soil resistivity equipment may, or in most cases may not detect this narrow layer of the drilling muds around the pipe.

  • If the backfill is typical soils, the drilling muds will migrate into the soil after several years.

  • If the backfill is in granite or similar rock, the muds may remain in place for many years.

• Deep Layer (Apparent)

  • This layer is used to get the most accurate results with a minimum of a 100-foot depth or 30.5  meters.  This layer is used to assess Inductive Faults and Steady State inductive voltages. 

  • Note:  It has been reported that many practitioners use the common CP type soil resistivity meter readings with the calibrated 5’ intervals wiring that is limited to 20’ that matches the 20’ deep ground rods on towers.  These data may be useful where resistivity readings are low (<1000 ohm-cm) and there are slight changes in other layers.

•  Pipe Layer (Barnes/Corrosive)

  • This layer should always be around the depth of the pipeline.  Typical depths run from 3 to 6 feet or 1 to 2 meters except for HDD crossings.  It is also used to calculate the current density of amps/m2.

• Conductive Resistivity Layer (Surface)

  • This layer should always be the top surface layer.  Typical depths run from surface to 10 feet or 3 meters.  It used to calculate conductive faults, step/touch potentials and surface potentials or ground potential rise.

Note:  Barnes Layers - Below is a schematic of these three (3) major layers to consider bulk and specific layer resistivity.  Any of these layers can be varied in depth based on the geo layering and resistivity layers related to pipeline depth. 

NACE/AMPP - Excel Spreadsheet(s) are typically used to calculate these multiple layers. 

Schematic of Barnes Multi-Layers Soil Resistivity for AC Modeling and Mitigation

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When pipelines are in the proximity of a power line, it is subject to induced or conductive  effects depending upon the operational status of the power line. When a phase wire carries an electrical load, a magnetic field is produced around the wire which links the coated pipe. This mutual effect causes AC voltage and current to be induced into a parallel pipeline.

During a lightning strike or episodic upset, the AC power line will experience a short circuit condition i.e., fault. During the fault period which can last from micro to milliseconds to several seconds, the power system becomes unbalanced. One phase wire carries a much larger current than the others which may be up to 30 times or more than that carried in normal operation.  From this unbalance, the magnetic induction may increase from several hundred to a thousand times induced voltage levels.

During a fault, the current flows into the ground at the faulted and through the shield wires to the adjacent towers. This ground current flow adds an additional (conduction) component of voltage to that produced because of the magnetic field (induction). If the current is sufficiently large, a direct arc between the closest tower leg and the pipeline may be initiated which could lead to coating or pipeline puncture.

 ACPT Fault Voltage and Current program models both:

• Inductive coupling

• Conductive or resistive coupling including arching to the pipeline (Closest Distance)

Most faults are due to inductive coupling which produce peaks at pipeline locations where physical or electrical discontinuities occur.  This can occur at any tower along the right of way.  Since the magnitude of the induced voltage peak is location dependent, all faults at each tower must be analyzed at fault exposure.  High peak induced voltage levels may result in several locations.

The ACPT program allows the user to check the All box to get an initial picture of these locations for mitigation. Under the Pipeline Tab, Select Full Section determine the closest distance (Section Number)  to a tower and compare results.  Rerun again to determine the effects of these towers.  For more accurate results, it is recommended to run several towers to determine earth/ground average resistance in these identified areas of concern. 

The appropriate mitigation should be used for both induced steady state and fault conditions.

• Voltage peaks – Discrete Anodes

• Large voltage peak sections – Parallel wire such as copper grounding 

Complex collocated pipeline and powerline systems require an iterative process that engineering judgement and experience is required.  It usually takes one or two mitigation design changes to achieve the desired cost-effective results. 

Pipeline grounding for mitigation typically uses discrete or deep anodes to reduce induced individual voltage peaks.  If induced voltage levels for steady state or fault conditions exceed industry acceptable levels, AC mitigation grounding implementation is required.

AC mitigation analysis is used to determine induced voltage reduction for grounding systems that consist of an individual discrete grounding such as horizontal buried conductors or vertical deep anodes.  In addition, these grounding systems could consist of existing pipeline components such as:

Casings

• Electrically isolated with individual decouplers

• Electrically or mechanically shorted – Decouplers not required

Isolating flanges to stations with electrically grounded piping

• Electrically isolated with individual decoupler

• Electrically or mechanical shorted – Decouplers not required

Vertical or horizontal anodes

• Deep vertical anode

• Horizontal remote anode(s) 

It should be noted when casings and isolating flanges are mechanically and or electrically shorted to ground, the Discrete Ground box should be checked in the Mitigation Tab of the AC Mitigation program.  To determine resistance to ground of the casing or the station, use the AMPP/NACE remote ground techniques to measure this resistance to earth.

Note:  To reduce larger sections of induced voltages, distributed systems such as vertical or horizontal anode strings and parallel continuous horizontal copper cable or zinc can be used with properly spaced decouplers to the pipeline(s),

Understanding Coating Resistance

Before calibrating the modeled induced AC voltages, an understanding of coating resistance quality is needed. The question comes up is are there a rule of thumb of values that can be used.  Yes and No, because the age, quality, or condition of the coating is one factor, whereas the soil resistivities are another to be considered.  When they are used together, then a more accurate assessment can be made.  How do initially assess coating quality:

·       Excellent (Typically Less than 2 years with no change in CP current demand)

·       Good (Typically greater than 2 years to 10 years and/or with minor change in CP current demand)

·       Fair (Typically where the CP current demand has a moderate change from original current requirement design)

·       Poor (Typically where the CP current demand has increased significantly with major coating deterioration and high CP demand).

Estimating Coating Resistance 

Four (4) parameters - pipe diameter, pipe depth, coating resistance, and coating thickness are required.. Coating resistance is the most subjective of all the parameters in that field measurements.  The resistance is a function of the coating quality, the average size of the coating holidays, the layer soil resistivity etc.  Guidelines for estimating average coating resistance are shown in the table below.

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If more accurate coating resistance assessments are needed, it is recommended to run field tests for coating resistance or coating conductance.  These surveys are expensive and time consuming.  Also, see AMPP/NACE Conductance test methods “Measurement of Protective Coating Electrical Conductance on Underground Pipelines.”

Calibration of Coating Resistance 

Once the average coating resistance values have been established, calculate the induced steady state voltages, and compare them to several AC potential pipeline sites measured in the field.  It should be noted that the power loads (amps) on the AC power lines should be the same as in the ACPT calculations.  These values must be the same to adjust the coating resistance and to achieve comparable results in the field.  This is also a good check to align the data for more accurate results in modeling to the real world.

Regarding span factors with and without water are based on bending stress and deflection.  Larger diameter pipe spans require saddles for stability.   

Many standards that require pipes to be filled with water are based on bending and shear stresses not to exceed 1,500 psi and a deflection between supports not exceed 0.1 inches. 

Other factors to be considered are as follows:

• Pipe is assumed to have standard W.T.

• No concentrated loads i.e., valves

• No changes of direction

• Horizontal plane

• Maximum deflection of span is limited 1 inch

• Stress intensification factors of components not considered

The Pipeline Toolbox calculates the Hoop Stress, Maximum Allowable Bending Stress, Maximum Bending Moment, Maximum Span Length due to deflection with and without water using a factor of 10.  This statement was added to address the issues of deflection.

What value represents or what number to use

• Deflection L/360 (Default) is the most conservative factor if related information is unknown.

• Deflection L/270 is used when this information is known. Example residual stresses from construction activities are often present. These stresses are often difficult to evaluate accurately but can be disregarded in most cases. However, it is the engineer's responsibility to determine whether such stresses should be evaluated.

• Deflection Other is used when other factors need to be applied.

• Pipe Hydrotest will reduce the span length calculations due to the additional weight

• Hydrostatic Deflection Factor is based on the pipe being exposed.

• Hoop stress

• Bending Moment

• Length Bending

• Length Deflection

• Total Length of Span

Note:  Exposure to a failure of a buried pipe poses less consequence than from exposed piping.