Post on 12-Apr-2018
4th Annual Sucker Rod Pumping Workshop
Hilton North Hotel, Houston, TexasSeptember 9 – 12, 2008
A Web-Based Failure Diagnosis And Frequency Reduction System, Featuring Imaging Of Rod-pumped Producing Wells
John P. Rogers, Engineering Manager VisuWell Services
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 2
Well Failures Significantly Increase Lifting Cost
• Non-sanded workovers are the single largest controllable lifting cost• Minority of wells often constitute the majority of repeat failures and
workover cost in a field (80/20 rule)• Root cause of failure is absolutely critical to capitalize on the systems
and techniques to optimize rod-pumped wells and lower failure frequencies
INDUSTRY WELL FAILURE COST, $/BblASSUMING 20 BOPD AVERAGE PRODUCTION AND A RANGE OF WORKOVER COSTS
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Failure Frequency
$ Pe
r Bar
rel
$20,000 $30,000 $40,000 $50,000 $60,000 $70,000
Estimated Workover Cost, Excluding Production
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 3
Effective Preventive Maintenance Tool• VisuWell System critical component of PM
– Corrective Maintenance• Typical failure/repair process of workover
– Preventive Maintenance• Scheduled: not typically done in oil production due to cost
and logistics• On condition: run during a failure induced workover
– Condition based monitor: VisuWell Rod/Tubing Scans, Deviation Survey provide a snapshot of operating conditions in near real time
– Combined with failure history forms the basis for a failure trending system
• VisuWell data visualization tools allows operator to see failure patterns
– Improvement Maintenance• Redesign completion to prevent failure recurrence
– Mitigation solution supports timely redesign
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 4
• Most wellbores are not truly vertical• 37% of industry well failures are tubing-
related.• Rod-on-tubing wear is #1 cause of
tubing failures• Failure frequency in many cases flattens
despite optimization efforts• Inspection of the rod string DURING
workover is desirable in order to correlate to depth
– Existing wellhead “tubing scans” have historically been problematic
– A low cost deviation profile is needed to enable real time visualization of wear patterns
– Correlating tubing condition; rod condition; deviation/dogleg and; sideload is mandatory to diagnose the cause & solution
– Often, important well data has been lost, was archived, may be incomplete and is very time-consuming to analyze
More real-time information of exactly what is happening downhole in the production
conduit is required for failure prevention
More realMore real--time information of exactly what is time information of exactly what is happening downhole in the production happening downhole in the production
conduit is required for failure preventionconduit is required for failure prevention
BackgroundTotal Failures - Before & After Optimization
0
10
20
30
40
50
60
70
80
90100
110
120
130
140
150
160
170180
190
200
210
220
230
240
250260
270
280
290
300
Failu
res
Per M
onth
Before Optimization After Optimization
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 5
Failure Mitigation Options• Improved procedures
– Rod and tubing handling practices
– Controlled displacement rod make-up
– Corrosion inhibitors
– Rod & tubing inspections
– Operating parameters optimization
– Surface & downhole equipment design optimization
• Technology innovations
– Fluid level gauging
– Intelligent Pump-Off Controllers & variable speed drives
– SCADA systems to manage the data streams
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 6
Failure Mitigation Options• Downhole equipment optimization & improvements
– Rod guides
– Sinker bars
– Tubing/Rod rotators
– Fiberglass rods
– Plastic/Nylon coatings/Polyethylene liner
– Looser fit/reduced friction pumps
– Conversion from beam pumping to other artificial lift methods
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 7
Tubing Deviation – Wells Are Rarely Vertical
• Drilling contractor generally does not consider production issues when drilling the well
• Minimal deviation data availability in typical mature sedimentary basins
• High cost of a “designed-for-drilling” gyroscope survey
• Tubing deviation is NOT the same as casing
• Well positional changes through reservoir drainage and geological events
• “Pulling” on the tubing to set the anchor is questionable in overcoming tubing compression
– The string is subject to thermal expansion
– May be applied only to the first dogleg, potentially leaving thelower tubing zone in compression and subject to buckling.
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 8
Tubing Condition
• Conventional wellhead tubing scans suffer shortcomings 1, 3
– Ganged sensor outputs and minimal number of sensors
– Speed-sensitive (amplitude and resolution)
– Amplitude-only signal does not consider flaw geometry
– Poorly centralized and no signal correction
– Many systems use surface-contacting sensor shoes that “ride”the tubing
– Results are extremely operator-dependent
– Insufficient data allows repeat failures
– Poor root cause failure analysis
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 9
Sucker Rod Condition• Wellhead rod scan previously not available
– Reclamation plant inspections do not match rod condition to tubing condition or deviation during workover
– Rod conditions are also a function of pump operating dynamics, not well geometry alone
– Rod reclamation plants can offer superior inspections but no positional well data
– Rod body diameter correlation to tubing wear by depth
• Massive time and effort to collect, collate and analyze all the data
• Data has not been available before the well goes back into production
– Insufficient data allows repeat failures
– Poor root cause failure analysis
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 10
System Description• Measurements:
– Deviation profile in tubing sizes from 2 3/8” to 5”
– Sucker rod condition based on pitting, cross-sectional area (CSA) & diameter
– Tubing condition based on pitting, CSA and wall thickness
– Non-contact diameter measurements of rod string
– All measurements calibrated to internally traceable standards
• Present calculated rod and tubing condition to the operator which eliminates the need to perform constant human interpretation of a complex analog signal envelope
– Final output provided in one foot resolution web-published data throughout the well depth
– Provide a three-dimensional image of the producing wellbore with zoom capabilities on a standard Windows PC
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 11
System Description
• Provide and expert system driven failure mitigation solution at the well site during well service and simultaneously web-publish it anywhere in the world
• Provide means for tracking current and historical failures
• Eliminate the requirement for additional well servicing equipment
• Minimize interference with the normal well servicing and workover process
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 12
Sensor Barrel
Front – ElectronicsAccess PanelConnector Panel
Centralizer
Rig Floor Sensor Package• Self contained rig floor system to
capture the following:
– Rod and tubing condition
• Rod/Tubing magnetic analysis
• Digitize raw sensor outputs on rig, improving the signal-to-noise ratio
• Tubing and Rod Size specific sensor barrel inserts
– Measure rod, tubing, guide and coupling OD
• Correct signal amplitude
• Detect tubing crush, couplings
• Measure rod guide and coupling diameters
– Rod and Tubing String Depth
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 13
Rig Floor Sensor Package• Depth driven system data acquisition
- Depth-based digitization- Uniform .2 inch data resolution at any pulling speed
• Centralizer - Designed to limit tubing and rod to within ½” of
eccentricity- Compensate for changing sensor-surface
offset• RFSP enclosure designed to bear the load of a rod
string• Use non contact sensors
- Size-specific sensor assemblies for tubing and rods
• Accommodate pulling a “wet” tubing string if necessary
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 14
Deviation Profile Tool• Deviation profile tool (DPT)
– MEMS-based 3 axis inertial system for determining the inclination and azimuth of a tubing string.
– Principle characteristics of a high end inertial system without using magnetic corrections.
– Measurement provides accurate inclination profile with .5 degree accuracy and azimuth changes within 10 degree accuracy
– Rig Inclination and azimuth change and rate of change is used to calculate side-load of the rod string on the tubing, as a function of PPRL
• Depth display unit- System for displaying speed and depth to rig operator
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 15
WELLMAP+Database Tools
WELLMAP+Dev ProfileTbg ProfileRod ProfileEng Calcs
Wear Solution
Field Service Unit Software Module Block Diagram
Rod Scan
Hi-ResRod data
Hi-ResTbg data
Tubing Scan
DPT MemoryDUMP
PLS
RT DisplayMake Condition Call
SYNC
Local DBCentral DB
Operator
Customer
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 16
Spraberry Trend Well Completed in July 2007
• TAC @ 7,954 ft & pump @ 9,200’– 3 HIT failures 7,700 - 8,000’– Pump moved up to 8,042’– Failed again in the same zone
• Two distinct zones of high side load– 6,369’ - 6,420 ft -
7,912’ - 7,968’– Installed guides from 500
ft above the upper zone of high side load to immediately above the pump
– High side load required increased guide spacing density
• Significant H2S corrosion on rods and tubing, leading to a modified inhibitor program
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 17
Permian Basin Clearfork Well• Three failures in 14 months at less than 500’
• 35 fiberglass rods at top of well• Green band tubing in current failure zone• What is causing these failures?
Tubing is wearing because of 2.5o
inclination at 225’
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 18
Permian Basin San Andres Well• Drilled > 20 years ago
• Pump @ 4,887’
• 410 BFPD; 73 BOPD
• 3 HIT failures in 19 months
• 167 lbs sideload @ 3,640’
• 6.57o @ 4,571’
• HIT @ 2,945’
• Guides suggested 2,951’ – pump
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 19
California Repetto Well• Pump @3,200’
• 9 Failures in 52 months– 3 rod parts between 1,000’ –
1,600’
– 3 HIT’s between 2,400’ –2,800’
– >600 lbs sideload @ 750’ and 1,750’
• Rods stacking out in compression <600’, causing tubing and rod wear
• Apply wear solution for high sideload zones
• Rod buckling at 2,400’ – 2,750’
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 20
Economics• Economic case for recurring failure prevention can be compelling
– At $30,000/workover, payback in less than six months can easily be achieved
– Well service costs are increasing
– Deferred production at present crude pricing has high PV10 value
– Puts focus on the cost of failure and the failure frequency, NOTthe number of hours for the workover
• However, there are considerations
– 6-8 hours of incremental pulling unit time
– Additional service cost
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 21
• Rule of thumb
– Lower lifting costs
– Pareto’s Rule – 20% of the wells are 80% of the failures
– Prevents one future failure in the next year
– INCREMENTAL cost is less than half the failure cost
Economics
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 22
Conclusions• Provides detailed real-time data from elements critical to failure frequency
analysis and mitigation
– Real time condition based analysis techniques employed
– Failure root cause analysis is significantly enhanced
• Graphical imaging allows very quick assessment of wellbore conditions and solution development
– By identifying failure root cause and applying a mitigation solution before the well is returned to production, a repeat failure can be avoided
• A relatively small investment provides attractive rate of return in preventing recurring failures
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 23
Conclusions• Deviation and resultant rod-on-tubing sideload is not the sole
determinant of wear and failure –
– Rod string buckling
– Corrosion
– Tubing buckling…others
• True failure root causes tend to be combinations of conditions
– Imaging the entire downhole conduit provides strong illustrationof downhole problems
– Data correlation provides superior information upon which to take corrective action
– Absence of a condition can lead to the preferred solution
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 24
Conclusions• The relatively small increase in well servicing cost is more than
repaid in reduced future failures
– Many lifting cost components are not controllable, failures are highly controllable
– Lower FPWPY
– Increase annual production
– Reduce equipment replacement costs
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 25
Copyright
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Other uses of this presentation are prohibited without the expressed written permission of the company(ies) and/or author(s) who own it and the Workshop Steering Committee.
Sept. 9 - 12, 2008 2008 Sucker Rod Pumping Workshop 26
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