CSI Oilfield: A Guideline to Conduct a Proper ESPCP Dismantle, Inspection & Failure Analysis By: Ken Saveth January 2018 The moment an Electric Submersible Progressing Cavity Pump (ESPCP) has been installed, the possibility exists that it could fail for some reason. There are a plethora of reasons not all of which are related to the ESPCP components themselves. The purpose of this work is to provide a generic guideline for writing a Dismantle, Inspection Failure Analysis (DIFA) Report for an ESPCP. The intent is to provide a guideline on how best to gather information and what data to gather to conduct a DIFA and it does not make one an expert on drawing conclusions. This work will outline the various types of data needed to be gathered so as to provide the necessary information that will allow the reliability engineer or dismantling persons the critical tools with which a solid determination of the Root Cause of Failure can be made and a comprehensive DIFA Report written. Without all of the necessary information, any cause of failure reached would be inconclusive and often nothing more than a guess. Additionally, it will outline and suggest the information needed to be included in the report itself and suggest an information flow that will help make the DIFA report much easier to follow and ultimately be understood. Like a Forensic Scientist in a crime scene investigation, gathering the correct type and quantity of critical information, knowing important chronological sequences of events and taking proper component photographs are paramount to conducting a successful DIFA, writing an acceptable report of findings and ultimately in reaching an accurate Root Cause of Failure. This generic DIFA outline will highlight the basic steps needed to conduct a proper dismantle, inspection & failure analysis for an Electric Submersible Progressing Cavity Pump. P a g e 1
INSTRUCTION The following information/documents are to be provided (whenever possible) in ALL DIFA reports in the order as listed: 1. Initial Well Data from which the PCP System was designed. PSD, Desired Production, completion (tubing/casing), perforations, BHT, etc. are all to be included. It is critical to confirm that current reality (what is actually installed in the well) matches the original design. This is why the ORIGINAL design files are to be provided and reviewed in conjunction with all of the other data stated in this DIFA Work Instruction. P a g e 2
2. Well History Well Name Install Date Start Date Failure Date Pull Date Well # xxx July 4, 2015 ~July 6, 2015 August 06, 2015 ~August 07, 2015 Time in Hole Run-Life Casing Diameter Prod. Rate 33 Days 33 Days 7 ~1,098 m 3 /d (6,907 BFPD) Statement of Root Cause of Failure & Associated Recommendations The C-FER Technologies document (1999) is often used by reliability engineers to provide a common terminology for classifying, recording and storing information specific to ESPCP failures. Reason for Pull Primary Failed Item Primary Failed Item Descriptor Failure Cause Mechanical PCP Stator Elastomer cut from sand Sand P a g e 3
3. Completion Details (I.e. Well Schematic of Completion Diagram). See sample below. Client: Section: GE O&G AL Field: Rig: T -1 Well: Run: Drawing Version: Date : AS BUILT 4-Jul-16 Note s: CONVENT IONAL INST ALLAT ION. INST ALL PCP ST ABILIZER @ MID OF ST AT OR. NOT ICE: Using Spa ce Out Ca lcula tor V2.5.1 Rotary Correction between rigs: 1.5" x 40' Polished Rod 9.00 ' Rig Floor to Tubing Spool: 14.00 ' Dual Drive Tubing Hanger: 1.08 ' w/ 2-75 HP ABB Motors S/N: Rod Stretch 18.46 inches Using SOC V2.5.1 Lift Off Tag Bar (LOTB) 17 Inches Safety Margin Distance 12 Inches Final Test Readings Total Space Out 48 Inches Intake Pressure: 1440 psi Disch Pressure: 1443 psi Temperature: 128 deg F No of Cable Bands installed: 331 EconmyProtector: 147 Tubing Hanger (5-1/2" LTC top & bottom) Normal Clamps: 5 Special Clamps: 4 5-1/2", 15.5# J55 LTC Pup TEC line for Sensors of Tubing Joints 146 Incl. 4 in completion Total # 5-1/2"x31', 15.5# LTC K55 Tubing # Jts of 5-1/2", J55 LTC Tbg 142 to Surface 1-1/4" Gr 97 Special HS Rods (w / 1 1/8" pins) Drain Nipple Set Depth 4,500.46 Ft. 1.11 Ft. 5-1/2" Drain Nipple 4000# 1 joint 5-1/2", top @ 4,501.57 Ft. 30.40 Ft. GE Disch pressure Sub 4,531.97 Ft. 1.14 Ft. 1 Jt. Tbg. 5 1/2" GE Discharge Pressure Sub 1 joint 5-1/2", top @ 4,533.11 Ft. 31.41 Ft. 1 Jt. Tbg. 5 1/2" 5 1/2" LTC Coupling 5 1/2" Isolation Nipple Isolation Set Depth@ 4,564.52 Ft. 1.08 Ft. Stainless Steal Capillar Press Tube 4.625" ID 1 Jt. Tbg. 5 1/2" 1 joint 5-1/2", top@ 4,565.60 Ft. 31.56 Ft. 5 1/2" PCP Centralizer Centralizer Depth @ 4,597.16 Ft. 0.67 Ft. 50K Shear Coupling 1 joint 5-1/2", top@ 4,597.83 Ft. 31.00 Ft. 1 Jt. Tbg. 5 1/2" X-over Set Depth@ 4,628.83 Ft. 0.74 Ft. 4 1/2" LTC x 5 1/2" LTC X-over Top of PCP Stator @ 4,629.57 Ft. 30.25 Ft. PCP Stabilizer National Oilwell Varco Stator Rod String Arrangement Top): WEIGHT=22Kibs (Bottom to STRING STATOR,32-1800 OB FINISHED (MSX4)* 1-1/4" Rod String: Rotor, 1-8' Pony rod, 1-HS Grade 97 rod, 50K shear coupling, D32-1800 S/N: 4219461-5 30.25 Ft. HS Grade 97 rods (Qty below ), 40' Polished Rod (does not include pony rods used for space out) National Oilwell Varco Rotor ROTOR,32-1800 FINISHED* D32-1800 S/N: 4219462-5 Pony Rod Lengths 10' Rotor Length: No of Ponys Used 28.41 Ft. 1 Tag Bar 3 1/2" EUE Pin 3 1/2" EUE collar, Tag Bar Set Depth@ 4,659.82 Ft. 1.25 Ft. 3 1/2" EUE x 4 1/2" EUE Pin x Pin 4-1/2" Pup Joint (Top)@ 4,661.07 Ft. 4.17 Ft. 4 1/2" EUE collar PUP JOINT,N-80 4 1/2" EUE X 4' (PA- 405) Excalibre No turn tool No turn tool Set depth 4,665.24 Ft. 1.76 Ft. Tool 4-1/2" x 9-5/8" SN: 100854 4 1/2" EUE x 4 1/2" LTC Xover collar 4-1/2", N80 Perf Joint w / 300 holes (1/2" dia) Perforated Joint (top)@ 4,667.00 Ft. 32.31 Ft. 4 1/2" LTC Box x 2 7/8" Pin GE Intake - Temp/Press sensor- 7"cntz sub GE Sensor Assembly (top) 4,699.31 Ft. 6.60 Ft. GE Sensor Assembly (Bottom) 4,705.91 Ft. S/N: FZ2K22371P Gravel Pack Packer Depth per K035 R3 As Built DWG RH 4,749.00 Ft. Completion details such as well schematics allow for the review of the complete PCP system as it relates to the entire well and well profile. The location of the PCP equipment itself in relation to the well s perforations, packers, casing shoes, liners, DLSs, etc. can play a crtical role in the analysis of pulled equipment and the ultimate DIFA outcome. P a g e 4
4. Equipment List see sample listing below. The inclusion of the Equipment List as installed is important when cross referencing this with the original design file for a few reasons. It is important to confirm that what was installed was the same as what was initially designed or nor. If not, it poses the question of Why not? It is also important when discussing DIFA findings with Engineering so that the proper equipment and their respective Part Numbers and Serial Numbers can be referenced for any manufacturing or supplier related issues. 5. Deviation Survey Analyze DLS as it applies to the Measured Depth (MD), Total Vertical Depth (TVD) and Pump Setting Depth (PSD) to ensure that we are not set in a DLS not to exceed 0.5 /100 ft. (or 30 m). It is advised to run a Bend Analysis program if available to confirm internal component stresses are not exceeded. Be cognizant of dogleg severities that could potentially cause excessive bending stresses within the system components if the ESPCP system operates below this point. P a g e 5
6. Pull Report Notes (Some Best Practice examples are included below) Observations while pulling provide a critical point during which pertinent data relative to the pulled equipment can be gathered. It is a ONE-TIME opportunity to capture evidence that if missed, is gone. An example of this might be taking oil samples from the seal section while it is still vertical and just pulled before it is laid horizontally in a box, trucked across the field and into the shop where fluids may have mingled. 7. Sequence of Events The sequence of events is meant to show chronological events for the well in question (as shown below). Events such as Commissioning Date, Trip due to High Torque, Low Torque, No Flow, etc. all play a role in analyzing the chain of events from the Install/Commissioning Date until the Failure Date. What is being looked for, are unique markers or events that could have played an role in the failure. P a g e 6
8. Operational Data Operational data is equally important as the sequence of events in that it shows visual trends for critical parameters. Increasing/decreasing amperage, dropping production rates, increases in pump intake pressures with a corresponding drop in pump discharge pressures can be important pieces of operational evidence when evaluating a failure. The example chart above, indicates dropping pump discharge pressure, rising motor temperature along with corresponding erratic motor current all just before the VSD tripped. Pump intake pressure is a good indicator for well s static and operating conditions. It is a good indicator for casing pressure and well draw down. Internal motor temperature when close to maximum allowed temperature may suggest checking correct HP rating of the motor and oil used for the application (higher HP motor may be recommended for next install). In addition, operational changes could be recommended to reduce stress on motor. If motor is running cool may suggest using smaller HP motor. Sudden spikes seen during operations would mean changes in well bore conditions. Pump discharge pressure and pump in take pressure are part of Total Dynamic Head (TDH) calculation and when combined with discharge temperature can provide good information about fluid volume and viscosity (so called PVT data) and Application Engineers may utilize for better equipment sizing). When looking at vibration data note should be made regarding sudden spikes seen which could be helpful and could be indicator of for example increasing sand content in the pump. However, careful interpretation requires combinging several other signals (such as intake pressure, temperature). Appendix in the end has an SPE paper which has very useful practical examples of how to interpret particularly vibration signals. Summary of Important Data Types and Sources Useful for DIFA Well profile, life history and prior DIFA reports Initial sizing and design report Installation, pull and field reports VSD operational data Amp charts, or motor amperage data P a g e 7
Downhole monitoring data (sensor data) SCADA Data Log of choke settings and choke setting when failure occurred. Production data (water cut, oil, & gas) Log of actions taken prior and after the shutdown (e.g. number of restart attempts, sequence of events.) Chemical treatment history Cable condition (age, number of splices, test data), MLC, Pothead, Pigtail, Feed Through 9. Radiation Data (When available) ALL used downhole equipment arriving at a service center must undergo a NORM survey before it is received. This entails a scan of the entire length of the pump/motor assembly and the external wrap of cable with the gamma probe. Any other sub-parts or equipment should undergo a similar thorough scan. Each NORM survey must be documented and the corresponding equipment marked accordingly. This process will dictate one of three handling procols, depending upn the readings. Equipment may be considered NORM-free when it is specified by a specific regulation for release or it is 50 ur/hr, where no regulation exists. When personnel dis-assembles and/or services equipment or otherwise cause NORM to be disturbed (potential airborne or skin contact), an action level of 20 ur/hr or twice natural background level whichever is higher shall be used as an action level where no regulatory and/or personnel exposure limits exist. The monitoring instruments generally available for performing NORM screening surveys are not intrinsically safe unless specifically designed for that purpose; therefore, personnel should determine the need for a Hot Work Permit in areas with potential for flammable or explosive environments. Survey instruments should be calibrated by the manufacturer or by a certified calibration lab; the intervals of which should not exceed 12 months. DISMANTLE OBSERVATIONS (NOTE: TO INCLUDE ALL SYSTEM COMPONENTS) EACH System Component is to be listed even if it was not dismantled so as to ensure that all components are included in the report. To be included is a summary of the component dismantle followed by appropriate photographs as shown in the example below. P a g e 8
A. MOTOR SUMMARY Motor inspection forms provide key details that should be captured. Look for evidence based on electrical megger testing and oil condition (dielectric strength). Additionally observations could look for scale, corrosion on housing, mechanical, electrical (including MLC, pothead, end coil burns) and heat damage, sealing areas for water intrusion (drain and fill plugs, O-rings and elastomeric components for damage or heat degradation, cuts, feathering, explosive decompression, compression set), shaft wear and rotation check (axial and lateral), condition of thrust bearing and runners, rotor and stator, head and base bushings for wear, scoring, and sleeves for discoloration, wear, scoring. The table below is a good way to organize key observations related to motor. External condition Oil condition Electrical condition Stator Rotors Rotor bearings Thrust bearing and runner Leads and terminals Shaft Head and base bushings Good Water and bitumen present in oil, dielectric of 12.4 kv Φ-Φ AB = 1.2Ω BC = 1.2Ω CA = 1.2Ω Φ-G A-G = 0MΩ B-G = 0MΩ C-G= 1.2MΩ Good condition Good condition Good condition Good condition, light scoring Base insulators were swollen likely from heat Good condition Head bushing was loose Summary Arc marks were found at the base plate of the motor (near the y-point). Bitumen and water were present in the motor. Motor Picture Examples Motor leads at head Typical rotor & rotor bearing Failure Analysis Summary with Root Cause of Failure - Details Incorporation of C-FER Failure Codes C-FER Failure Codes as outlined in above and in C-FER document R035 STANDARD ESP Failure Nomenclature Version x.x should be incorporated. P a g e 9
B. SEAL SUMMARY Inspection table in Appendix should be filled out to document seal observations. Follow seal dismantle work instruction (see Appendix). Some of the key observations should check for seal shaft rotation (axial and lateral), wear, run out and compare with factory settings/dimensions, frosting on shaft due to transfer of say bushings on to shaft, pitting, galling or one sided wear, pressure leak test on seal should be conducted in accordance with the work instruction, carefully examine condition of mechanical seals under a microscope to see wear tracks due to abrasives that may have led to leaks, check condition of bag measure diameter particularly in case of observed swelling to ascertain damage due to chemical attack), condition of clamp and making sure bags were tightly secured, O-ring and all elastomeric materials for signs of degradation, compression set, feathering, extrusion, cuts, explosive decompression, look for damage to runner, uneven wear, fretting (i.e. wear due to vibration or relative motion), and thrust bearing pads for extent of wear and compare with pump down thrust wear to draw conclusion. The table below is an example summary for a seal. External condition Good Axial Shaft Movement Top: N/A Base: N/A Travel: N/A Head Well fluid + water +oil Parallel Upper Bags Well fluid & some sand on outside. Mainly clean oil inside. Oil condition Black oil/well fluids inside & out. Some Parallel Lower Bags sand present outside. Thrust bearing Chamber Black oil with metal particles above runner as well as sand & debris. Bags Good condition, oil and well fluid throughout. Sand present on bags Mechanical Shaft Seals Mechanical shaft seal in-between labyrinth and bags was in good condition. Other seals still intact, but coated with well fluids Bushings and sleeves Good condition Thrust bearing and runner Heavy/Severe down thrust scoring, up thrust bearing looks okay. Shaft The shaft was broken just above the thrust runner. Summary The shaft was broken just at the thrust runner. A fair amount of sand/debris was found above runner and also above the top mechanical seal. The thrust bearing & runner had severe down thrust wear but no up thrust wear. P a g e 10
Seal Picture Examples Thrust Bearing and Thrust Runner Broken Seal Shaft C. PUMP SUMMARY Use pump inspection form and tear down procedure to document the result. In general, during dismantle look for signs of corrosion/coating damage, erosion, scale build up, presence of abrasives, housing damage (drag marks, scratches, straightness, vibration damage that may have signs of cable marks, signs of heat due to spinning diffusers. Check to see of the rotor can be turned within the stator. Make note if the impeller and diffuser stacks are difficult to pull out. Check O-rings and elastomeric material for cuts, compression set, feathering, swelling, hardness/brittleness due to heat. Take careful measurements for shaft, impeller and diffuser as in the inspection form to compare against drawing. In general, wear in dimensions is expected more near the base side of the pump as abrasives get grinded out as they move upward towards pump top. Compare thrust washers with new thrust washers for their condition, particularly thickness and brittleness. Carefully look for damages to splines at both ends of the shaft and look for any signs of incomplete engagement with the couplings, pitting, one side wear below sleeves and any galling or erosion. Condition of intake screens can also be helpful in failure analysis. Tables below are BASIC summaries of key pump (Rotor & Stator) related observations. (NOTE: They are only snippets of the applicable data sheets. P a g e 11
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Pump Pictures D. SENSOR SUMMARY Look for signs of corrosion, erosion or mechanical damage of the housing. Inspect condition of wye point and in general connection between motor and sensor making sure the thermocouple is recording actual winding temperature and not the oil at the base temperature as that may lead to motor burns due to incorrect sensing for tripping the motor in case it runs hot. The table below is an example to summarize documentation of sensor summary. External condition Good condition Oil Condition N/A (Zenith) Osiris: Sensor Flange Condition HV Feed Thru Tm Probe Feed Thru Sensor Function Test Result Sensor Rerun Recommendation Passed No Summary: The sensor was in working condition, but does not meet the rerun criteria due to more than hundred repeated power cycles. Data signal loss during operating condition was tied to faulty surface choke assembly caused by ESP electrical surge. Sensor Picture (look for fluid ingress in case of electrical failures) P a g e 13
Failure Cause The severe corrosive pitting on the motor housing (through the housing in places) allowed well fluids/water to enter into the motor causing it to fail electrically Failure Summary Reason for Pull Primary Failed Item Primary Failed Item Descriptor Failure Cause Electrical Motor Corroded motor housing Water entry into the motor Recommended Action Items: Recommended Action Items are to include any course of action that is recommended to eliminate or reduce the frequency of occurrence of the cause of failure. DIFA SAMPLE RETENTION It is absolutely essential to be sure that critical samples from a DIFA are retained in a safe place until such time that the DIFA has been officially closed. Set aside a quarantine location in the shop whereby these samples can be stored. Once the DIFA has been officially closed out, the samples can be discarded. SUMMARY In summary, conducting any dismantle, inspection & failure analysis has many steps all of which are critical in the process of determining the root cause of any failure. Leaving out any one of the steps may result in a less then optimal report and the inability of being able to effectively determine the failure cause. Use this process as a guideline & adapt the steps when necessary. P a g e 14