3. Final Inspection Report.pdf

US International Boundary and Water Commission

Amistad Powerhouse Final Inspection Report

Prepared by

For

USIBWC

MWH Project No. 10509265

September 7, 2016

USIBWC Amistad Powerhouse Final Inspection Report

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Executive Summary This Final Inspection Report (Report) documents the observations of the equipment inspected during the turbine pit piping, turbine pit corrosion, head cover bolts and pressure vessel inspections from June 21, 2016, through June 24, 2016, as well as the equipment inspected during the hoist inspection from June 28, 2016, through June 29, 2016.

The scope of work for the first week of inspection focused on the turbine pit corrosion, piping, pressure vessels and the head cover to stay ring fastening bolts for each unit, and the nine (9) plant pressure vessels.

Sub-contractors HCMS and API NDT assisted with the inspection. The scope of work for the second week inspection focused on the two 40 ton intake gate hoists, the 125 ton Fulton Bridge Crane hoist, and the 10 ton Draft Tube Gantry Crane hoist. The Fulton Bridge Crane hoist and the Draft Tube Gantry Crane hoist were inspected on June 28, 2016. The two intake gate hoists were inspected on June 29, 2016.

The following describes the results of the inspection, grouped into the categories of equipment inspected:

Pressure Vessels, Turbine Pit Piping and Supports, Turbine Pit Paint and Corrosion, Head Cover Bolts and Hoists.

Pressure Vessels

MWH inspected nine pressure vessels. Based on the results of NDE testing and visual inspection of pressure vessels 2V1, 2V2, 2V3, 2V4, 2V5, 2V6, U1 Governor Air/Oil Tank and U2 Governor Air/Oil Tank it is MWH’s opinion that these pressure vessels do not need to be replaced. The wall thicknesses of pressure vessels typically are designed and fabricated to be larger than the nominal design thickness to provide a margin against corrosion, and the wall thicknesses of these eight tanks were found to be for the most part, larger than the nominal design thickness. MWH inspected both inside and outside and didn’t see any cracks nor any significant effects of corrosion. MWH recommends the outside of these tanks be cleaned, and these tanks continue operating as designed.

Due to the inability to perform adequate visual inspection of the interior surfaces, the raw water pressure vessel is recommended to be replaced. This is not an immediate need for replacement since no crack indications were observed, but this replacement should be taken into consideration over the next two to five years with periodic monitoring in the meantime. During that time period, this pressure vessel can continue to be used as long as it is operating well and periodic inspections show that there is no significant deterioration. Until the tank is replaced, MWH recommends that periodic flushing be done to the tank and the raw water system to remove sediment that accumulates over time.

MWH will provide procurement specifications for this tank based on the data provided from the existing tank. All instrumentation can be removed from the current tank and installed on the new tank.

Turbine Pit Piping and Supports

MWH inspected the turbine pit piping and pipe supports for both Units 1 and 2 by means of NDE testing and visual inspection. The piping that was inspected included the steel draft tube water depression line, the steel governor oil line, the copper bearing oil line, and the copper water line. The instrumentation line piping was not a part of this scope of work.

While UT measurements showed that the draft tube depression piping wall thickness was close to the nominal design wall thickness, visual inspection of the inside of this piping showed a significant layer of

9/7/2016 Page | ii hard deposits coating the interior surface of the piping. Visual inspection of the exterior of the piping indicates there is extensive exterior corrosion. The draft tube depression piping is presently not accessible for replacement and cannot be replaced until the wicket gate mechanism is removed. The piping will still operate as needed however the flow might be restricted due to the build-up of deposits on the interior of the pipes. Due to the infrequency of use of the draft tube water depression line, MWH does not recommend replacement of this in the immediate future. However, when a significant outage can be scheduled within the next ten years in which these pipelines will become accessible, it is recommended that this piping be replaced so it is available and in good condition for future use. An opinion of probable cost for the replacement of the draft tube water depression piping has been excluded, because major disassembly of other equipment components is required to permit access for inspection of the covered up areas so that an accurate estimate can be made. If USIBWC would like to make any cosmetic rehabilitation, including grinding of the corrosion and old paint away and repainting, this could be done during the next two to five years.

The copper water piping wall thickness measurements were found to be close to the nominal design thicknesses, but visual inspection of these pipe lines showed a coating on the inside of the piping. It is recommended for the copper water piping to be flushed clean of the sediment that has coated the interior lining of the piping. Once cleaned, the copper water piping can continue to operate as designed and is recommended to be reused, except for the sections where flow meters are installed. Significant galvanic corrosion was observed at the sections of piping with flow meters at the flow meter flanges. It is recommended that these sections be replaced with stainless steel parts, and all dissimilar metals be isolated to reduce corrosion potential. The flushing of the piping, the replacement of the flow meter sections, and any cosmetic upgrades should be done within the next two to five years.

All pipe supports below the turbine pit walkway are recommended to be replaced due to evidence of galvanic corrosion. During replacement, the pipe supports should be fabricated from steel and isolated from contact with the piping by use of gasket material. Additionally, there should not be contact between any non-similar metals, such as fasteners, orifice plate flanges, etc. The pipe supports above the turbine pit walkway are in good condition and are recommended to be reused.

The bearing and governor oil piping have been deemed to be in good condition and do not need replacement, therefore they are recommended to continue to be used at this time.

Turbine Pit Paint and Corrosion

The turbine pits were visually inspected to assess accessibility for lead paint removal and containment, as well as potential challenges in mitigating the turbine pit corrosion. The lead paint is recommended to be removed within the next two to five years. Mitigation of the rust and corrosion can be postponed until a significant outage is scheduled within the next ten years when the major components can be disassembled and the corrosion can be addressed. Similar to the opinion of probable cost for the replacement of the depression line piping, an opinion of probable cost for the corrosion and rust mitigation has been excluded because major disassembly is required to permit access for inspection of the covered up areas so that an accurate estimate can be made.

The lead paint needs to be removed, but containment from pipelines and waterways will be challenging, given the relatively large square foot area of lead paint coverage and its proximity to these pipelines and waterways. Areas around piping will need to be carefully chemically stripped. This is a slower and more

9/7/2016 Page | iii expensive process than blasting, sanding and grinding, and the contaminants will need to be properly disposed of. For areas that are not near piping and which can be locally sectioned off without threat of contaminants seeping into the bottom of the turbine pit, 100% impermeable tarps and curtains could be set up and more “at risk” methods could be utilized, such as sanding or grinding. The traps and curtains need to be in good condition, would need to overlap each other, and would need to be completely fastened together in such a way as to seal off the escape of lead contaminated paint particles and debris.

From the results of the visual inspection, the corrosion occurring in the turbine pit appears to be superficial and cosmetic. Therefore, in order to address this corrosion, once the lead paint has already been removed from the turbine pit, it is recommended to grind or remove all corrosion products, clean the surfaces, and repaint.

Once all the lead paint and corrosion is removed from the turbine pit, MWH recommends the turbine pit surfaces that have had paint or corrosion products removed be repainted for protection from future corrosion.

Head Cover Bolts

MWH performed visual and NDE inspection on 10% of the head cover to stay ring coupling bolts for each unit. Each bolt inspected was UT and MT tested searching for any sign of an indication or crack, the presence of which would require bolt replacement. The UT test looked for internal indications, while the MT test looked for surface indications. The results of the head cover bolt inspection showed no signs of indications or cracks in the head cover bolts. MWH does not recommend that the head cover bolts be replaced at this time, but MWH does recommend that USIBWC procure a set of the correct spare head cover bolts in case they may be needed in the future. MWH has excluded the opinion of probable cost for the spare set of head cover bolts because IBWC should already have an accurate cost estimate based on previous head cover bolt purchases.

Hoists

MWH inspected two intake gate hoists, the powerhouse bridge crane hoist, and the draft tube gantry crane hoist.

The two Intake Gate Hoist machinery were observed to be in good condition. However, as the full gearbox information is not available for the existing gear reducers as catalog cuts were not available, MWH had to assume that the gear reduction according to the nameplate was correct. According to MWH calculations the hoist capacity appears to be less than the rated 40 ton capacity. Thus, MWH recommends the hoist be upgraded to a full 40 ton rated capacity. In addition, in the absence of a worm reducer, there is a need for a control brake. Therefore, MWH recommends an electrical brake be provided in the hoist.

The Powerhouse Bridge Crane was found to be in good condition with only minor maintenance (cleaning and lubrication) required for various sheaves, wheels, line shaft and drum bearings. The condition of the paint was good on the Powerhouse Bridge Crane.

Several deficiencies were observed during the Draft Tube Gantry Crane Hoist inspection that MWH recommends be corrected prior to using the gantry for its intended purpose. Specifically, both 9/16” diameter wire ropes had damaged strands and the mechanical geared limit switches were found to be faulty, both of which require replacement. Gantry cab currently is an open cab, with all control equipment

9/7/2016 Page | iv subject to element under normal circumstances, thus it is also recommended that control panel in the cab should be suitably protected from the environment. In addition, the gantry requires application of a new coat of paint to provide continued protection to the gantry structure and components from corrosion.

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Table of Contents Executive Summary ........................................................................................................................................ i

Purpose

Background

Inspection Team

Tasks Performed

Findings and Observations

Pressure Vessels

Turbine Pit Piping and Supports

Turbine Pit Paint and Corrosion

Head Cover Bolts

Hoists

Recommendations

Priority Phasing

Appendices

Appendix A – Daily Inspection Reports

Appendix B – API-NDT Inspection Report

Appendix C – Konecrane Inspection Report

Appendix D – Pressure Vessel Inspection Photographs

Appendix E – Unit 1 Turbine Pit Piping and Support Inspection Photographs

Appendix F – Unit 2 Turbine Pit Piping and Support Inspection Photographs

Appendix G – Unit 1 Turbine Pit Paint and Corrosion Photographs

Appendix H – Unit 2 Turbine Pit Paint and Corrosion Photographs

Appendix I – Unit 1 Head Cover Bolt Inspection Photographs

Appendix J – Unit 2 Head Cover Bolt Inspection Photographs

Appendix K – Hoist Inspection Photographs

Appendix L – Reference Data from Site Visit

Appendix M – Unit 2 Disassembled Piping Photographs

Appendix N – Hoist Capacity Verification Calculations

Appendix O – Opinion of Probable Cost Supporting Information

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Purpose MWH was contracted by United States International Water and Boundary Commission (USIBWC) to perform design services for improvements at the USIBWC Amistad Dam. The Scope of Work includes conducting an existing condition inspection, providing a report and analysis for the conditions observed, and providing construction drawings and specifications to support a bid process for USIBWC to obtain a construction or a service contract for the implementation of identified repairs or modifications to the facility.

Based on existing conditions the overall objective of this project is to inspect, analyze and recommend corrective measures to repair, replace or improve the two turbine pit areas and associated components, including pressure piping, pressure vessels, head cover to say ring fastening bolts, the intake gate hoist system for both units, the 125 ton Fulton Bridge crane hoist and the 10 ton draft tube gantry crane hoist.

This Final Inspection Report (Report) documents the observations of the equipment inspected during the turbine pit piping, head cover bolt and pressure vessel inspection from June 21, 2016, through June 24, 2016, as well as the equipment inspected during the hoist inspection from June 28, 2016, through June 29, 2016.

Background On July 31, 2014, the United States Army Corps of Engineers (USACE) submitted a Corrosion Inspection Report for the USIBWC Amistad Powerhouse. In this Corrosion Inspection Report, USACE identifies three categories of recommendations – Category A, Category B and Category C. According to the USACE Report, Category A recommendations should be executed within the 2 to 5 years following the report submission, Category B recommendations should be executed within the 5 to 10 years following the report submission if the hydroelectric units go through a major rehabilitation, and Category C recommendations should be executed within the 5 to 10 years following the report submission if there is no major rehabilitation for the hydroelectric units.

Category A from the USACE report consisted of four recommendations:

Ultrasonic inspection of the head cover bolts, pressure piping wall thickness, and pressure vessel wall thickness;

Verification of the capacity of each intake gate hoist and verification of the depth of the sheave wire rope grooves of the intake gate hoists;

Repair and recoating of intake gates with USACE Coating System No. 4 and the replacement of the cathodic protection system for the intake gates;

Recoating of the draft tube gates with USACE System No. 5-E-Z.

Category B from the USACE report consisted of two recommendations:

Repainting of the turbine and turbine pit, draft tube cone, penstock, and penstock transition areas;

Replacing the corroded pipe supports in the turbine pit areas.

These recommendations, along with the remaining recommendations listed Category C from the USACE Report, led USIBWC to begin a rehabilitation program. USIBWC started by addressing portions from the USACE recommendations and contracted MWH for the following services:

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Inspection and verification of the capacity of each intake gate hoist system including the depth of the sheave wire rope grooves, to be conducted by a qualified crane manufacturer and/or a certified structural engineer;

Inspection and verification of the capacity of the 125 Ton Fulton Bridge Crane Hoist and the 10 Ton Draft Tube Gantry Crane Hoist including the depth of the sheave wire rope grooves, to be conducted by a qualified crane manufacturer and/or a certified structural engineer;

Performance of Non Destructive Testing (NDT), including ultrasonic inspection, to determine the structural integrity of the head cover bolts, pressure piping, piping supports and pressure vessels;

Inspection of corrosion inside the turbine pits of Unit 1 and Unit 2;

Provide alternative piping supports that address the corrosion induced by dissimilar metals;

Address the problem of dissimilar metals for all items covered by the service agreement, including hoists, piping and vessels, and provide technical solutions;

Provide detailed OSHA and EPA approved procedures for the removal of lead based paint from the turbine pit area and repainting the affected areas.

Inspection Team

DELETED

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Tasks Performed First Week of Inspection

The scope of work for the first week of inspection focused on the turbine pit corrosion, piping and the head cover to stay ring fastening bolts for each unit, and the nine (9) plant pressure vessels. Sub-contractors HCMS and API NDT assisted with the inspection. The first week inspection activities are summarized below.

Turbine Pit

Similar to the inspection of the pressure vessels, the turbine pit piping wall thicknesses were measured with the Phase II UTG-2900 ultrasonic thickness gauge, and the paint thicknesses with a DeFelsko MIKROTEST III Thickness Gage paint thickness measuring tool. Due to the poor surface finish on much of the turbine pit piping (due to corrosion and paint chipping), thickness measurements were made at clean, un-corroded locations. The piping that was inspected included the steel depression line, the steel governor oil line, the copper bearing oil line, and the copper water line. The instrumentation line piping was not a part of this scope of work.

Segments of the Unit 2 steel draft tube water depression line piping and the Unit 2 copper packing box sealing water line piping were disassembled for visual inspection. The documented observations are discussed later in this Report.

Head Cover Bolts

Each unit has 96 head cover to stay ring coupling bolts. Ten bolts from each unit were identified for removal and inspection. The bolts were strategically chosen based on easy access to disassemble and reassemble and for a balanced distribution around the perimeter of the turbine head cover. Once the bolts were removed from the head cover they were cleaned, labeled, and inspected by means of ultrasonic inspection using a scanner (Sonatest Sitescan 130 S/N 1301603C) and a transducer (DuPont NDT Instruments Model #GEW-5 1.0” 5Mhz S/N 12034 0o angle) and wet magnetic particle inspection using a fluorescent magnetic particle spray, a magnetic yoke (Parker Probe 6 Amp S/N 1502) and a UV

9/7/2016 Page | 4 light (Spectroline BIB-150B S/N 757269). These NDE inspections were performed to identify the presence or absence of linear indications or cracks for each bolt. Once the testing was completed on the bolts and the bolts were deemed suitable for reuse, the threads were coated in anti-seize and the bolts were reinstalled in their original positions and tightened to the design torque.

Second Week of Inspection

The scope of work for the second week inspection focused on the two 40 ton intake gate hoists, the 125 ton Fulton Bridge Crane hoist, and the 10 ton Draft Tube Gantry Crane hoist. The Fulton Bridge Crane hoist and the Draft Tube Gantry Crane hoist were inspected on June 28, 2016. The two intake gate hoists were inspected on June 29, 2016.

All these points are common to all four hoists, as applicable. Actions taken include visual inspection of:

Structural members for bent or damaged members, loose connection hardware, guards and cracked welds.

Shaft & couplings for evidence of damage, misalignment, leaking seals, loose keys, coupling bolts, and covers. Inspected for vibration, cuts, loose or worn keyways, misalignment, wear, loose bolts, loose bearing caps and proper lubrication.

Gear boxes for damage or worn gears, for evidence of misalignment or loose keys, and for proper lubrication. Inspected for evidence of oil leakage, bearing damage, overheating, and abnormal wear.

Visually inspected for worn teeth, loose components, keys, guards, covers, proper lubrication and oil levels.

Brakes for wear, linkage, pins, cams, springs, linings, smoothness or drum and disc clearance.

Inspected for proper solenoid air gap, loose core lamination, delay in brake release, as applicable.

Sheaves or pulleys for wear, damage, sheave groove radius, worn bushing, bearing, pins, loose bolts, lubrication lines and fittings.

Load blocks for damage, wear, hook swivel, wear to sheaves, plates, loose pins, bolts, guards, capacity marking, drip pans and gaskets.

Wire ropes, sockets, swivels, pins, connection, check for broken wires, strand and lubrication. Checked for 10% or less reduction in size. Checked for corrosion, kinks, crushing, protruding core, cable clamps and proper lubrication. Visually inspected for wire rope tight on drum. Visually inspected rope guides for wear, adjustment and proper operation.

Rope drums for excessive wear, crack in grooves, sharp ridges, drum bearings, excessive noise, vibration, lubrication and proper cable seating.

Wiring for damage insulation, evidence of overheating, loose connections, proper sizing, all moisture or watertight fittings. Checked the condition of drive, load capacity of the disconnect switch and all other electrical components.

Warning devices for warning tags and proper operation of sirens, horns, bells and lights. Checked all switches and wiring.

Limit switches for proper operation of high speed and low speed travel limit switches. Verified hook height and hook to floor distances.

Hoist speeds and holding of load for proper operation of variable or multiple speeds and high speed and low speed limit switches.

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Findings and Observations

The wall thickness of the steel draft tube water depression air pipe line, the steel governor oil pipe line, 9/7/2016 Page | 6 the copper bearing oil pipe line, and the copper shaft packing box sealing water supply pipe line were measured and recorded by ultrasonic NDE methods, and the interior and exterior surfaces were inspected by visual methods, similar to the pressure vessel inspection.

Photographs of the pipe supports were taken throughout each turbine pit. These photographs will be used in the design phase to determine where each pipe support needs to be replaced. Special attention was paid to pipe connectors that used dissimilar materials, but were not electrically isolated from each other, such as steel clamps to support copper piping, flow meters’ carbon steel flanges connected directly to copper piping, or carbon steel bolts for flanged connections without isolating kits.

Draft Tube Depression Piping (Steel)

Surface corrosion and pitting was observed on the exterior surface of the 3” and 4” diameter steel depression line piping for both Units 1 and 2. Surfaces for NDE inspection were strategically chosen to be clean surfaces unaffected by corrosion to increase the likelihood of an accurate reading. Although the exterior surface showed corrosion, the extent of the corrosion is superficial and is not significant enough to require immediate replacement.

The thickness measurements were taken along horizontal pipes, vertical pipes, and elbow connections, at multiple locations around the perimeter of the pipe segment cross section. The recorded measurements were then compared against the design pipe thicknesses of both the 3” and 4” pipe. The pipe thickness measurements for both Unit 1 and Unit 2 depression line piping are summarized in Table 3 below.

Table 3: Depression Pipe Thickness Measurements

Depression Pipe Thickness (in inches) Unit 1 Unit 2

Design Thickness 0.216 (for 3” pipe Sch 40)

0.237 (for 4” pipe Sch 40)

0.216 (for 3” pipe Sch 40)

0.237 (for 4” pipe Sch 40)

Minimum Thickness .152 0.201 .183 .224 Maximum Thickness .238 0.241 .243 .265 Average Thickness .198 0.221 .218 .241

The minimum thickness measured is 70% of the design thickness for the 3” pipe in Unit 1, 85% of the design thickness for the 4” pipe in Unit 1, 85% of the design thickness for the 3” pipe in Unit 2 and 95% of the design thickness for the 4” pipe in Unit 2. The minimum wall thickness measurements signaled that a visual inspection of the interior walls of the depression piping was necessary, although the average wall thicknesses were all within 10% of the design thickness.

A segment of this piping in Unit 2 was disassembled for visual inspection. The inside surface of the piping was found to be coated in a hard deposit approximately a ¼” thick, as seen in Figure 9. The deposit could not be easily removed, although the visual inspection did show that the pipe walls are not corroding away, and therefore the pipe wall thickness appears to be sufficient for future operation.

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Figure 9: Depression Piping Interior Lining

A significant portion of the 3” draft tube depression piping is located below the wicket gate operating mechanism and will not be accessible for replacement until a major rehabilitation of the units is scheduled.

Also, the 4” embedded draft tube water depression piping between the turbine pit and the draft tube depression air receivers cannot be replaced. Therefore, partial replacement of all exposed draft tube depression piping in the turbine pit is not recommended in the near future since the embedded piping sections and the exposed piping below the wicket gate operating mechanism already will be restricting air flow permanently until the entire line can be replaced. Instead, MWH recommends USIBWC wait until a significant outage can be scheduled and then replace the entire line. In the meantime, USIBWC can perform cosmetic updates to the accessible piping if they so wish, but MWH does not believe the cosmetic rehabilitation is a necessity.

Governor Oil Piping (Steel)

The exterior surface of the steel governor oil piping for both Units 1 and 2 was found to be in good condition, shown in Figure 10. The wall thickness was measured for the piping at various sample locations.

The governor oil piping geometries were not listed in the drawings provided at the site, but from inspection this piping is assumed to be 2” outer diameter schedule 40 steel piping, with a nominal wall thickness of 0.154”, and 3” outer diameter schedule 40 steel piping, with a nominal wall thickness of 0.216”. The wall thickness measurements for the governor oil piping are summarized in Table 4 below.

Table 4: Governor Oil Pipe Thickness Measurements

Governor Oil Pipe Thickness (in inches) Unit 1 Unit 2

Design Thickness 0.154 (2” Sch 40) 0.216 (3” Sch 40) 0.154 (2” Sch 40) 0.216 (3” Sch 40) Minimum Thickness 0.151 0.206 .164 .211 Maximum Thickness 0.160 0.228 .166 .254 Average Thickness 0.155 0.214 .165 .229

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The minimum and average thicknesses of the governor oil pipes are very close to the nominal thickness of the piping. A visual inspection of this piping was not deemed to be needed. The governor oil piping is considered to be suitable for continued use and does not need to be replaced.

Figure 10: Governor Oil Piping

Bearing Oil Piping (Copper)

The visual inspection of the exterior surface of the bearing oil piping showed the piping to be in what appeared to be good condition as seen in Figure 11. The wall thickness was measured at various locations to identify and record a general sampling of wall thicknesses for this piping system.

The bearing oil piping consists of 2.5”, 2” and 1” copper piping. As was previously explained, the 1” copper piping could not be measured for wall thickness due to the pipe size falling below the minimum value for measurement. The measurements for the 2.5” and 2” piping are shown in Table 5 below.

Table 5: Bearing Oil Pipe Thickness Measurements

Bearing Oil Pipe Thickness (in inches) Unit 1

Design Thickness 0.083 (2” pipe) 0.095 (2.5” pipe) Minimum Thickness 0.078 0.092 Maximum Thickness 0.082 0.094 Average Thickness 0.081 0.093

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The minimum and average thicknesses of the bearing oil pipes are very close to the nominal thickness of the piping. A visual inspection of this piping was deemed not necessary. The bearing oil piping is considered to be suitable for continued use and does not need to be replaced.

Figure 11: Bearing Oil Piping

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Shaft Packing Box Seal Water Supply, Bearing Cooling Water Discharge and Supply, and Runner Seal Cooling Water Supply Piping

The exterior surfaces of the copper piping (shown in Figure 12) for both Units 1 and 2 were found to have superficial surface damage and deteriorated exterior protective painting, but without exterior signs of corrosion and no observable pitting. The exterior surface damage was superficial and is not expected to affect future operation and does not require immediate replacement, except for pipe sections where flow meters are installed. It is recommended that piping sections with flow meters be completely replaced with sections of stainless steel piping with stainless steel flow meter orifice flanges and stainless steel orifice plates. It is recommended to install dielectric unions on both ends of stainless steel piping and compatible copper tube connections on both sides. It will be assessed if existing orifice plates can be reused after examination of the removed flow meter sections. The current flow meter orifice flange corrosion is shown in Figure 13.

Figure 12: Copper Piping Lines

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Figure 13: Flow Meter Corrosion on Copper Piping

Thickness measurements were not taken for these water supply pipes, due to the small size of piping.

Instead, a segment of the shaft packing box sealing water supply piping in Unit 2 was disassembled for visual inspection. The inside surface of the piping was coated in a soft, easily removable sediment deposit approximately a 1/8” thick (see Figure 14).

Based on internal inspection of one section of copper piping in Unit 2 indicating soft sediment inside the pipe, it is recommended to flush the copper lines upstream of the flow meters before new stainless steel flow meters are installed.

Figure 14: Copper Pipe Interior Sediment Lining

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Based on the inspection results, the copper piping does not require replacement, except for the flow meter sections. The flow meter flanges show significant corrosion. There is a combination of dissimilar materials with copper piping, carbon steel orifice flanges and stainless steel orifice plates. These dissimilar metals with no electrical isolation facilitate galvanic corrosion. Therefore, sections of piping containing these corroded flanges are recommended to be replaced with completely stainless steel piping, flanges, and orifice plates. Any parts that are dissimilar materials need to be isolated to prevent future corrosion.

The pipe lines can continue operation, although the sediment might restrict flow if not properly flushed, and flow meter readings may be affected by sediment accumulated inside the copper lines.

Turbine Piping Supports

The inspection of the turbine pit piping supports was divided into two areas, one above the turbine pit platform and one below. The supports above the turbine pit platform (seen in Figure 15) showed little signs of corrosion, whereas the supports below the turbine pit platform show significant signs of

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Figure 15: Pipe Supports above Turbine Pit Walkway

The turbine pipe supports below the turbine pit walkway (shown in Figure 16) were visually observed to be significantly corroded. Each pipe support location was documented for both Units 1 and 2. The photographs taken to document the pipe support locations are going to be marked up and included in submittals for a future contractor to use during pipe support replacement. These submittals will be created during the Design Package Task.

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Figure 16: Pipe Support Corrosion below Turbine Pit Walkway

Instrumentation Piping, Grease Piping and Gage Tubing

Instrumentation piping, grease piping and gage tubing were not inspected, since these systems were not a part of the agreed upon MWH Scope of Work. However, visual inspection of the turbine pit paint in both units showed that the instrumentation piping will be required to be at least moved away from the turbine pit liner before repainting can be done.

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Turbine Pit Paint and Corrosion The turbine pits (see Figure 17) were inspected to assess accessibility for lead paint removal and containment, as well as potential challenges in mitigating the turbine pit corrosion. They were also inspected with respect to the many guidelines and procedures that are mandated by Federal Law, which must be adhered to during the process of lead paint abatement. Also for the repainting there will be challenges maintaining a dry environment to insure proper adhesion of the new coating.

Removal of the lead based paint should preclude any replacement of pipes and pipe supports to avoid contamination of existing hydraulic and water systems. Electrical components should also be protected.

Figure 17: Turbine Pit Paint and Corrosion

Guidelines to minimize any potential exposure and to comply with all applicable federal, state and local regulations pertaining to management of lead-based paint (LBP) must be followed. Guidelines address issues such as inspection, worker certification, abatement, communication, housekeeping and recordkeeping.

Two categories of activities that impact lead based paint are “no risk” activities and “at risk” activities. “No risk” activities are defined as those that generate either no airborne lead or only low levels of lead dust in the air. Examples include:

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Paint intact lead based paint;

Minor hand scraping lead based paint;

Minor wet sanding lead based paint.

“At risk” activities are defined as those that are likely to generate moderate to high levels of lead fume or dust in the air and are of long or short duration of time. Examples include:

Hand scraping lead based paint;

Wet sanding lead based paint;

Electric sanding lead based paint;

Grinding or burning lead based paint;

Using a heat gun on lead based paint;

Removing lead based paint with chemical strippers;

Replacing windows with lead based paint;

Demolishing lead based painted structures.

averaged over an eight (8) hour shift triggers requirements for employee exposure medical surveillance, monitoring and training.

General Requirements for “No Risk” and “At Risk” Activities

Equipment and Supplies

The following supplies are necessary for any work involving surface preparation of lead paint:

Polyethylene sheeting (6 mil) Water spray bottle HEPA vacuum Waste containers Utility knife Scraper Duct tape

Personal Protective Equipment

The following personal protective equipment is required for “at risk” activities:

Disposable coverall Air Purifying Respirator with HEPA filters Eye protection Availability of showers for possible contamination

Work Practices – Interior Work

Plastic sheeting (6 mil thickness) shall be used to protect the following areas:

Floor surfaces of work area Furnishings (e.g. desks, chairs, computers, etc.)

Ventilation diffusers, vents, grills Air intake system run to the outside of the powerhouse for fresh air supply to the turbine pits Exhaust fans with collectors to capture airborne particles Restriction of work area to only trained contractor personnel experienced in lead paint abatement

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Training of on-site staff that will need to be in the work are in lead abatement procedures and personnel protection

Scraping and sanding of LBP shall be conducted using a spray water bottle to pre-wet the affected surface and to mist the air. Loose paint chip debris shall be HEPA vacuumed from the plastic sheeting before removal and disposal of the sheeting. Final cleaning of affected work surfaces shall be accomplished by wet wiping and HEPA vacuuming. Clean water or a high phosphate solution (i.e. 5% tri-sodium phosphate) shall be used.

As contract requirements are developed, MWH’s Lead Based Paint Abatement Consultant will be brought onto the team to ensure that the specifications and all federal, state and local laws and procedures are met.

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The ten head cover bolts from each unit were inspected by means of ultrasonic inspection, magnetic particle inspection, and visual inspection (see Figure 18). For the ultrasonic inspection, a Sonatest Sitescan 130 ultrasonic beam scanning device and a DuPont NDT Instruments transducer (see Appendix B for test equipment information and certifications) was used to look for linear or crack indications along the axis of each bolt. A potential indication or crack would be evidenced by return signals from the ultrasonic beam outside of the geometric signals that are expected. Any sign of an indication would warrant replacement of that bolt.

For the magnetic particle inspection, each bolt shaft was coated in a wet florescent magnetic spray, a magnetic charge was applied to the bolt using a Parker Probe 6 Amp S/N 1502 magnetic yoke (see Appendix B) and then visually inspected under a Spectroline BIB-150B S/N 757269UV light (see Appendix B). This test is used to identify any potential indications that have made their way to the surface of the bolt. When the fluorescent spray is applied and the magnetic yoke is turned on, the metal particles in the coating will accumulate at any surface indication, thus revealing a crack.

Figure 18: (LEFT) UT Inspection of Head Cover Bolt; (RIGHT) MT Inspection of Head Cover Bolt

During our inspection, if at any point a bolt was found to have crack indications, the bolt would be replaced with a spare bolt, and five more sample bolts would be disassembled and tested. If multiple bolts would have been found to have indications, the recommendation would have been to replace all of the bolts.

Nineteen (19) of the twenty (20) inspected bolts showed no (zero) indications, and therefore do not require replacement. One head cover bolt showed a surface indication during the magnetic particle inspection, however the indication was minor and appeared to be a tooling mark, not a crack. To confirm that this minor indication was a surface tooling mark, a dye-penetrant test (PT) was run. The PT confirmed that the indication was minor (as seen in Figure 19) and the bolt did not need to be replaced.

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Figure 19: Unit 2 Bolt 7 PT Surface Indication

Each bolt head was visibly pitted, as shown in Figure 20. The pitting is superficial and is believed to be a result of chipping during the original installation, therefore MWH’s assessment is these bolts do not require to be replaced.

Figure 20: Head Cover Bolt Head Pitting

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As a result of inspecting 10% of all head cover bolts for both Units 1 and 2, since no significant indications were found, MWH recommends that the head cover bolts not be replaced at this time. MWH recommends that USIBWC procure a set of spare head cover bolts, because the spares that are currently at site are not the correct dimensions, as shown in the photo comparison in Figure 21 below.

Figure 21: Original Head Cover Bolt Size vs. Spare Head Cover Bolt Size

Spare Head Cover Bolts Currently on Site

Original Head Cover Bolts

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Recommendations

The draft tube water depression piping extends below the wicket gate arms and into the head cover. This piping is presently not accessible for replacement and cannot be replaced until the wicket gate mechanism is removed. This piping is also constantly submerged in water during unit operation due to the shaft seal packing permitting standing water in the turbine pit. Visual inspection of the exterior of the piping indicates there is extensive exterior corrosion. MWH’s measurements indicate relatively uniform wall thickness, which indicates wall thickness deviations from design values are likely minor. The piping will still operate as needed, however the flow might be restricted due to the build-up of deposits on the interior of the pipes. Due to the infrequency of use of the draft tube water depression line, MWH does not recommend replacement of this in the immediate future. However, when a significant outage can be scheduled within the next ten years in which these pipe lines will become accessible, it is recommended that this piping be replaced for future operation. An opinion of probable cost for the replacement of the draft tube water depression piping has been excluded, because major disassembly of other equipment components is required to permit access for inspection of the covered up areas so that an accurate estimate can be made. If USIBWC would like to make any cosmetic rehabilitation, including grinding of the corrosion and old paint away and repainting, this could be done during the next two to five years.

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The copper water piping is recommended to be flushed clean of the sediment that has coated the interior lining of the piping. Once cleaned, the copper water piping can continue to operate as designed and is recommended to be reused, except for the sections where flow meters are installed. The flushing of the piping, the replacement of the flow meter sections, and any cosmetic upgrades should be done within the next two to five years.

All pipe supports below the turbine pit walkway are recommended to be replaced due to evidence of galvanic corrosion. During replacement, the pipe supports should be fabricated from steel and isolated from contact with the piping by use of gasket material. Additionally, there should not be contact between any non-similar metals, such as fasteners, orifice plate flanges, etc. The pipe supports above the turbine pit walkway are in good condition and are recommended to be reused.

The bearing and governor oil piping have been deemed to be in good condition and not need replacement, therefore they are recommended to continue to be used at this time.

Turbine Pit Lead Paint Abatement, Repainting and Corrosion Mitigation

Rust, corrosion, and lead paint is abundant in both the Unit 1 and Unit 2 turbine pits. There are a few challenges with mitigating these issues. First, the existing lead paint needs to be properly contained during removal. Second, the instrumentation piping will need to be removed from their current installed positions to address the space restraints. Finally, for the corrosion, it only makes sense to mitigate the problem if the source of the corrosion will be controlled going forward. The time and cost to clean up the corrosion would not be financially economical if the problem might re-occur at a later date due to the constant pool of water sitting in each turbine pit.

The lead paint is recommended to be removed within the next two to five years. Mitigation of the rust and corrosion can be postponed until a significant outage is scheduled within the next ten years when the major components can be disassembled and their corrosion can be addressed.

Based on the limited scope of services for which MWH was contracted to provide and MWH’s observations performed, the lead paint found in the turbine pits is the only hazardous material or unsafe condition that MWH is aware of and would need to be addressed at the Amistad Power Plant. The lead paint needs to be removed, but containment from pipelines and waterways will be challenging, given the relatively large square foot area of lead paint coverage and its proximity to these pipelines and waterways.

Areas around piping will need to be carefully chemically stripped. This is a slower and more expensive process than blasting, sanding and grinding, and the contaminants will need to be properly disposed of.

For areas that are not near piping and which can be locally sectioned off without threat of contaminants seeping into the bottom of the turbine pit, 100% impermeable tarps and curtains would can be set up and

9/7/2016 Page | 23 more “at risk” methods can be utilized, such as sanding or grinding. The traps and curtains need to be in good condition, would need to overlap each other, and would need to be completely fastened together in such a way as to seal off the escape of lead contaminated paint particles and debris.

MWH has prepared an opinion of probable cost for lead paint abatement for the lead paint located in both Unit 1 and Unit 2 turbine pits from elevation 891.0 and elevation 880.0. Lead paint mitigation below the 880.0 elevation has been excluded due to accessibility constraints. Major disassembly is required in order to produce an accurate estimate for the lead paint abatement from elevation 880.0 and below.

From the results of the visual inspection, the corrosion occurring in the turbine pit appears to be superficial and cosmetic. Therefore, in order to address this corrosion, once the lead paint has already been removed from the turbine pit, it is recommended to grind or remove all corrosion products, clean the surfaces, and repaint. Similar to the opinion of probable cost for the replacement of the depression line piping, an opinion of probable cost for the corrosion and rust mitigation has been excluded because major disassembly is required to permit access for inspection of the covered up areas so that an accurate estimate can be made.

Once all the lead paint and corrosion is removed from the turbine pit, MWH recommends the turbine pit surfaces that have had paint or corrosion products removed be repainted for protection from future

MWH does not recommend that the head cover bolts be replaced at this time, but MWH does recommend that USIBWC procure a set of the correct spare head cover bolts in case they may be needed in the future.

MWH has excluded the opinion of probable cost for the spare set of head cover bolts because IBWC should already have an accurate cost estimate based on previous head cover bolt purchases.

Hoists

Intake Gate Hoists

As the full gearbox information is not available for the existing gear reducers, according to MWH calculations the hoist capacity appears to be less than the rated 40 ton capacity. Thus, MWH recommends the hoist be upgraded to a full 40 ton rated capacity. In addition, in the absence of a worm reducer, there is a need for a control brake. Therefore, MWH recommends an electrical brake be provided in the hoist.

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Appendices Appendix A – Daily Inspection Reports

Appendix B – API-NDT Inspection Report

Appendix C – Konecrane Inspection Report

Appendix D – Pressure Vessel Inspection Photographs

Appendix E – Unit 1 Turbine Pit Piping and Support Inspection Photographs

Appendix F – Unit 2 Turbine Pit Piping and Support Inspection Photographs

Appendix G – Unit 1 Turbine Pit Paint and Corrosion Photographs

Appendix H – Unit 2 Turbine Pit Paint and Corrosion Photographs

Appendix I – Unit 1 Head Cover Bolt Inspection Photographs

Appendix J – Unit 2 Head Cover Bolt Inspection Photographs

Appendix K – Hoist Inspection Photographs

Appendix L – Reference Data from Site Visit

Appendix M – Unit 2 Disassembled Piping Photographs

Appendix N – Hoist Capacity Verification Calculations

Appendix O – Opinion of Probable Cost Supporting Information

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Appendix A – Daily Inspection Reports

Daily Inspection Reports Site Inspection Reports from MWH Personnel at Amistad Dam

June 21, 2016 – June 24, 2016

Amistad Dam – Turbine Pit and Pressure Vessel Inspection Inspection Day Notes – June 22, 2016

Head Cover Bolt Inspection

At the end of the first day of the inspection, one bolt had been pulled from Unit 2. It had successfully passed UT, MT and visual inspection, however it had not yet been reinstalled due to water entering the Unit 2 turbine pit. This was previously explained in yesterday’s report.

This morning, the Unit 2 turbine pit had been drained and dried. Water from the vacated bolt hole was vacuumed out, the first bolt was coated in anti-seize, and the bolt was reinstalled. HCMS used a torque multiplier tool, which multiplies the input torque by a factor (in this case 18.5%), resulting in an output torque of higher magnitude. According to the head cover bolt fastening data drawing, the wet tightening torque for the head cover bolts is 760 ft-lbs. With the 18.5 multiplying factor, 42 ft-lbs of input torque was applied, resulting in 777 ft-lb of output torque. Accounting for losses in applied torque from the extension tools, this should result in about 760 ft-lbs of actual applied torque.

HCMS worked around the turbine pit, incrementally removing, testing and reinstalling 9 more head cover bolts in Unit 2. The location of the head cover bolts has been recorded, as well as the preliminary NDE test results. All 10 Unit 2 head cover bolts passed the UT tests. The tenth bolt tested showed a slight surface indication from the MT and subsequent PT tests, as shown in the pictures below. The indication did not appear to be structural, but rather a tooling mark from fabrication. The bolt was deemed to be suitable for reuse and was reinstalled.

Figure 1: Unit 2 Bolt 10 MT Results

Figure 2: Unit 2 Bolt 10 PT Results

Surface Indication

Surface Indication

The majority of the heads of the bolts were noticeably pitted. See the photos below. These bolts were deemed suitable for reuse, but the heads of these bolts should be monitored in the future.

Figure 3: Sample Pictures of Bolt Heads

Tomorrow, the Unit 1 head cover bolts will be removed, inspected and reinstalled.

Figure 5: Inside Unit 1 Governor Tank - Looking Up

Figure 6: Inside Decompression Tank - Looking Up

Figure 7: Inside Decompression Tank - Looking Down

Figure 8: Inside Governor Air Tank

Turbine Pit Piping

Peter was in charge of the piping inspection. He finished the UT piping inspections in both units for all piping except copper piping smaller than 1-1/2” in diameter because the NDE inspector did not have sufficient tools. Preliminary results show that the piping is in poor condition. Peter can elaborate for the inspection report.

Tomorrow, select pipe segments…