4th Annual Sucker Rod Pumping Workshop - ALRDC Annual Sucker Rod Pumping Workshop Hilton North...

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


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


• 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


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


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


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.


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


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


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


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


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


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


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


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


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


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’


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


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’


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


• 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


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


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


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


Copyright

Rights to this presentation are owned by the company(ies) and/or author(s) listed on the title page. By submitting this presentation to the Sucker Rod Pumping Workshop, they grant to the Workshop, the Artificial Lift Research and Development Council (ALRDC), and the Southwestern Petroleum Short Course (SWPSC), rights to:

– Display the presentation at the Workshop.– Place it on the www.alrdc.com web site, with access to the site to be as directed by the Workshop

Steering Committee.– Place it on a CD for distribution and/or sale as directed by the Workshop Steering Committee.

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.


DisclaimerThe following disclaimer shall be included as the last page of a Technical Presentation or Continuing Education Course. A similar disclaimer is included on the front page of the Sucker Rod Pumping Web Site.The Artificial Lift Research and Development Council and its officers and trustees, and the Sucker Rod Pumping Workshop Steering Committee members, and their supporting organizations and companies (here-in-after referred to as the Sponsoring Organizations), and the author(s) of this Technical Presentation or Continuing Education Training Course and their company(ies), provide this presentation and/or training material at the Sucker Rod Pumping Workshop "as is" without any warranty of any kind, express or implied, as to the accuracy of the information or the products or services referred to by any presenter (in so far as such warranties may be excluded under any relevant law) and these members and their companies will not be liable for unlawful actions and any losses or damage that may result from use of any presentation as a consequence of any inaccuracies in, or any omission from, the information which therein may be contained.The views, opinions, and conclusions expressed in these presentations and/or training materials are those of the author and not necessarily those of the Sponsoring Organizations. The author is solely responsible for the content of the materials.The Sponsoring Organizations cannot and do not warrant the accuracy of these documents beyond the source documents, although we do make every attempt to work from authoritative sources. The Sponsoring Organizations provide these presentations and/or training materials as a service. The Sponsoring Organizations make no representations or warranties, express or implied, with respect to the presentations and/or training materials, or any part thereof, including any warrantees of title, non-infringement of copyright or patent rights of others, merchantability, or fitness or suitability for any purpose.

4th Annual Sucker Rod Pumping Workshop - ALRDC Annual Sucker Rod Pumping Workshop Hilton North...

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