north cowden asset best practices to reduce rotw and rod pump failures
DESCRIPTION
North Cowden Asset Best Practices to Reduce ROTW and Rod Pump Failures Pete Maciula Production Coordinator Robert Ricks Lift / Downhole Specialist. Best Practice Documentation – This form is intended to capture - PowerPoint PPT PresentationTRANSCRIPT
North Cowden Asset Best Practices to Reduce ROTW
and Rod Pump Failures
Pete Maciula Production Coordinator
Robert Ricks Lift / Downhole Specialist
Best Practice Documentation – This form is intended to capture artificial lift related best practices being applied by OXY Permian’sNorth Cowden Asset Downhole Team.
Location: North Cowden Date practice began: 1999Date practice ceased: Current practice
Problems: 1. Excessive tubing failures in beam pumped wells with the majority caused by rod on tubing effects. 2. Excessive rod pump failures in beam pumped wells with the majority due to design, solids, over pumping, and/or corrosion.
Need:
The majority of the North Cowden tubing failures appeared to be caused by rod on tubing effects (wear/corrosion).
Several “Best Practices” were developed to reduce those cause of failures.
Indicators of success:
Realization of a 58.7% reduction in tubing failures since 1999.
Tubing Best Practices
Historical Tubing Failures
0
20
40
60
80
100
120
140
160
1999 2000 2001 2002 2003 2004 2005Projected
Several “Best Practices” were utilized in accomplishing the reduction of tubing failures (primarily due to ROTW):
1. Loose fit pumps (increased pump clearances).Recommended plunger to barrel fit clearances:
1-1/4” 0.004” to 0.006”1-1/2” 0.005” to 0.008”1-3/4” 0.006” to 0.009”2” 0.007” to 0.009”2-1/4” 0.007” to 0.010”
2. Recommend a maximum PRV of 240 Ft/Min.
PRV Ft/Min = (SL x SPM X 2) / 12
3. Sinker bars rather than 1” rods in bottom rod design to reduce compression. Recommended sinker bar utilization: 1-5/8” no-neck with 7/8” pin Gr K with 7/8” SH SM couplings in
2-7/8” tubing. 1-1/2” no-neck with ¾” pin Gr K with ¾” FH SM couplings in 2-
3/8” tubing.4. Rod rotators on problem wells and on all wells with rod guides.
Tubing Best Practices
5. Discourage the utilization of rod guides in the rod string. However, in wells with ROTW due to deviation where no other method has proven successful the utilization of Amodel PPA non-glass filled molded on rod guides with 4 guides per rod in IPC tubing and Amodel PPA 33% glass filled in bare tubing.
6. On well failure pulls with 2-7/8” tubing and with any wear on rods, removal of one 25’ rod and installation of 2 – 1” x 12’ plastic coated rod subs (one at bottom and one at top of string) to alternate the wear pattern. On subsequent pulls install one 25’ rod and remove the two subs. Continued process on subsequent alternative pulls.
7. Pump stabilizer rod subs.
Recommended pump stabilizer rod subs:
1”x4’ type 90 Gr KD sub with 7/8” pin and 3 Amodel PPA non-glass filled guides in 2-7/8” tubing.
7/8”x4’ type 90 Gr KD sub with 3/4” pin and 3 Amodel PPA non-glass filled guides in 2-3/8”.
Tubing Best Practices
8. Utilization of TK-99 IPC tubing from the marker sub (just above the TAC) down.
9. TAC landing tension of 18 points.
10. Performing WH tubing scanning on wells where excessive rod wear is found and on problem wells. When performing WH tubing scanning, the process of scanning all the tubing, including that below the TAC even if you know that tubing below the TAC to be bare and plan to replace with IPC in order to establish any wear or corrosion intervals.
11. Performing WH tubing scanning to include the classification of Double Green (31-40% wall loss) and utilization of this DG tubing in the top 1500’ of the tubing string while landing with Yellow or new tubing (designed more for cost reduction).
12. Utilization of Lufkin SROD and Theta RodStar for predictive wave equation programs.
Tubing Best Practices
13. SPOC settings:Maintain 150-200’ gas free fluid above pump at pump off.Maximum of 25 cycles per day.Maximum of 2 consecutive pump off strokes.Maximum of 2 consecutive load violation strokes.
14. More timely and accurate fluid level data.Utilization of Lufkin Ventawave and Echometer Model E equipment for fluid level data gathering.
15. Post failure follow up program by PFA and SPOC Tech.30 days post restoring failed well to production the PFA and SPOC Tech perform well analysis to include:
• Fluid level.• Pump cards – Startup, Shutdown, and Live Action.• Low and High Limits.• Run Times and Cycle Times.• Pump Off Strokes.• Dynamometer analysis.• Spreadsheet recording of any parameter changes made and when made.
Tubing Best Practices
16. Corrosion chemical program.– Corrosion monitoring:
Weight Loss Coupons.LPR probes (instantaneous corrosion rates).
– Corrosion inhibitor types: Oil soluble water dispersible chemical on low FAP wells (<800’ FAP). Water soluble chemical on higher FAP wells (>800’ FAP). Continuous treatment (water soluble) on problem wells.
– Corrosion inhibitor dosage based on total fluids:Batch treatment average 25 PPM.Increased to average 40 PPM in 2002. Continuous treatment average 25 PPM.
– Corrosion inhibitor treatment frequencies based on total production:
1 per week to continuous, based upon coupon data and well failure samples.Pouring 5 gallons of oil soluble water dispersible corrosion inhibitor down tubing prior to RIH with pump and rods on all failures.Circulation with Phosphoric acid of HIT problem wells post failure repair and restoration to production (after well pumps down to <500’ FAP) to combat under deposit corrosion, followed by a slug of inhibitor to reestablish film.
Tubing Best Practices
17. Root cause failure analysis.
– Oxy DHS on-site supervision.• Obtaining failure samples and photos on all
fails.– Excel failure database.– Integrated Solutions Team.
Tubing Best Practices
Need:North Cowden historical pump performance and pump component failure data indicated that there were five outstanding areas of concern:
1. Brass HVR pull tubes - wear and corrosion failures in the bending moment area.
2. Pump fit tolerances (.002” to .004” fits) – system and pump problems due to solids and friction forces.
3. Four piece, top load, insert guided cages (thin wall) – split and cracked cages.4. Lower extension couplings on tubing pumps (bare) – internal corrosion
failures.5. Plungers on tubing pumps (bare ID) – internal corrosion causing plungers to
split.
Pump specifications were developed in which these areas of concern were particularly addressed.
Indicators of success: Realization of a 59.7% reduction in rod pump failures since 1999.
Rod Pump Best Practices
Historical Pump Failures
0
10
20
30
40
50
60
70
80
90
100
1999 2000 2001 2002 2003 2004 2005Projected
2005 YTD Pump MTRBF
Less than 50 days = 151 ….100 = 3 101….250 = 1251….365 = 2366….730 = 2731….1000 = 11001….1500 = 31501…..2000 = 5Greater than 2001 = 7
• The development of pump specifications driven by local historical pump component failure data and industry best practices.
• Periodically review the pump specs and failure data so as to maintain an “Evergreen” program.
• Utilize the pump specs in conjunction with many of the afore mentioned “Best Practices” in the Tubing section.
Rod Pump Best Practices
The “Best Practices” pump specifications:
Valve Rod Insert PumpComponent: Specification:Top Bushing 316L SS (L has lowered carbon content)Collet Nut 316L SSValve Rod Grade “K” metalized (7/8” K gr rod w/ 316 SS spray coating)Collet Nut MonelTop Plunger Adapter MonelPlunger Spray Metal w/ Monel pinTV Cage Bottom load insert Monel w/ .075” clearance inserts
w/ short ball travelTV Ball Silicon Nitride, alternate pattern TV Seat Nickel Carbide, alternate pattern single lappedSeat Plug Brass hex onlyRod Guide 316L SS
Rod Pump Best Practices
Valve Rod Insert PumpComponent: Specification:Extension Couplings BrassBarrel Tube Brass ELNI coated (Brass Nickle Carbide)BDV Connector 316L SSBDV Jacket 316L SSBDV Cage Bottom load insert Monel w/ .075” clearance inserts w/
short ball travelBDV Ball Silicon Nitride, alternate patternBDV Seat Nickel Carbide, alternate pattern single lappedBDV Seat Plug Brass hex onlySV Cage Bottom load insert Monel w/ .075” clearance inserts w/
short ball travelSV Ball Silicon Nitride, alternate patternSV Seat Nickel Carbide, alternate pattern single lappedMandrel Adapter 316L SSHold Down Mandrel 316L SSSpacer Rings 316L SSGas Anchor Coupling 316L SSStrainer Nipple 24” perforated steel
Rod Pump Best Practices
Note: Spacing TV and SV ½” to 1-1/2” Maximum
Cages are three piece, bottom load, insert guided
Barrel and Plunger Tolerance
1-1/4” 0.004” to 0.006”
1-1/2” 0.005” to 0.008”
1-3/4” 0.006” to 0.009”
2” 0.007” to 0.009”
2-1/4” 0.007” to 0.010”
Vertical Discharge Guides
Rod Pump Best Practices
The “Best Practices” pump specifications:
Tubing Pump
Component: Specification:
Top Coupling J-55 API w/ TK-99 coated ID
Top Lift Sub 2’ Lathe cut J-55 nipple w/ TK-99 coated ID
Barrel Couplings 316L SS
Barrel Brass ELNI coated
Lower Barrel Extension 18’ Lathe cut J-55 nipple w/ TK-99 coated ID
Lower Coupling J-55 API w/ TK-99 coated ID
Seating Nipple 316L SS API
TV Cage Bottom load insert Monel w/ .075” clearance inserts w/ short ball travel
TV Ball Silicon Nitride, alternate pattern
TV Seat Nickel Carbide, alternate pattern single lapped
Plunger Spray Metal w/ Monel pins w/ TK-99 coated ID
Puller Assy 316L SS
Rod Pump Best Practices
Tubing PumpComponent: Specification:
SV Fish Neck 316L SS
SV Cage Bottom load insert Monel w/ .075” clearance inserts w/ short ball travel
SV Ball Silicon Nitride, alternate pattern
SV Seat Nickel Carbide, alternate pattern single lapped
SV Mandrel 316L SS
SV Spacers 316L SS
SV Lock Nut 316L SS
SV Gas Anchor Coupling 316L SS
Strainer Nipple 24” perforated steel
Rod Pump Best Practices
Note: Spacing TV and SV ½” to 1-1/2” Maximum
Cages are three piece, bottom load, insert guided
Barrel and Plunger Tolerance
1-1/4” 0.004” to 0.006”
1-1/2” 0.005” to 0.008”
1-3/4” 0.006” to 0.009”
2” 0.007” to 0.009”
2-1/4” 0.007” to 0.010”
Note: October 2002 made design change from 12” to 24” perforated strainer nipples (to increased area of strainer below SN). February 2003 made design changes to special clearance valve cages and alternate pattern valves (for solids and seat cracking problems).
Rod Pump Best Practices
North Cowden Asset
720 Beam Lift Wells
• 106 Mark II units (Avg 175.51 PRV)
• 265 Air Balance Units (201.3 PRV)
• 348 Conventional Units (179.2 PRV)
• 1 Rota - Flex Unit (196.80 PRV)
Average Well Characteristics• Beam unit with 144” – 168” SL x 7.76 SPM.
• Average 2.00” bore pump.
• Average PRV of 187.80 Ft/Min.
• Average production rate of 350 BFPD.
• Average total depth of 4534’ with 300’- 400’ of open hole.
• Average casing shoe depth 4203’.
• Average tubing set depth 91’ above TD.
• Average TAC set depth 4102’.
Average Failed Well
• 400 BFPD • 7.96 SPM • 148.94 Stroke Length
• 189.35 Polished Rod Velocity (Ft/Min)
• 98 Tubing Failure (JFS)
Historical Failure Frequency
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0.350
0.400
0.450
1999 2000 2001 2002 2003 2004 2005
Problem Well Count Defined as any Two Failures within 365 days
0
20
40
60
80
100
120
2000 2001 2002 2003 2004 2005
Failure Index Number“Cost per Failure x Failure Frequency”
1000
1500
2000
2500
3000
3500
4000
2001 2002 2003 2004 2005