North Cowden Asset
Best Practices to Reduce ROTW
and Rod Pump Failures
Pete Maciula
Robert Ricks
Production Coordinator
Lift / Downhole Specialist
Best Practice Documentation – This form is intended to capture
artificial lift related best practices being applied by OXY Permian’s
North Cowden Asset Downhole Team.
Location: North Cowden
Date practice began: 1999
Date 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.
Tubing Best Practices
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.
Historical Tubing Failures
160
140
120
100
80
60
40
20
0
1999
2000
2001
2002
2003
2004
2005
Projected
Tubing Best Practices
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 23/8” tubing.
Rod rotators on problem wells and on all wells with rod guides.
4.
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 nonglass filled guides in 2-7/8” tubing.
7/8”x4’ type 90 Gr KD sub with 3/4” pin and 3 Amodel PPA nonglass 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.
Rod Pump 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.
Historical Pump Failures
100
90
80
70
60
50
40
30
20
10
0
1999
2000
2001
2002
2003
2004
2005
Projected
2005 YTD Pump
MTRBF
Less than 50 days
51 ….100
101….250
251….365
366….730
731….1000
1001….1500
1501…..2000
Greater than 2001
=
=
=
=
=
=
=
=
=
1
3
1
2
2
1
3
5
7
Rod Pump Best Practices
•
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 Pump
Component:
Top Bushing
Collet Nut
Valve Rod
Collet Nut
Top Plunger Adapter
Plunger
TV Cage
TV Ball
TV Seat
Seat Plug
Rod Guide
Specification:
316L SS (L has lowered carbon content)
316L SS
Grade “K” metalized (7/8” K gr rod w/ 316 SS spray coating)
Monel
Monel
Spray Metal w/ Monel pin
Bottom load insert Monel w/ .075” clearance inserts
w/ short ball travel
Silicon Nitride, alternate pattern
Nickel Carbide, alternate pattern single lapped
Brass hex only
316L SS
Rod Pump Best Practices
Valve Rod Insert Pump
Component:
Extension Couplings
Barrel Tube
BDV Connector
BDV Jacket
BDV Cage
BDV Ball
BDV Seat
BDV Seat Plug
SV Cage
SV Ball
SV Seat
Mandrel Adapter
Hold Down Mandrel
Spacer Rings
Gas Anchor Coupling
Strainer Nipple
Specification:
Brass
Brass ELNI coated (Brass Nickle Carbide)
316L SS
316L SS
Bottom load insert Monel w/ .075” clearance inserts w/
short ball travel
Silicon Nitride, alternate pattern
Nickel Carbide, alternate pattern single lapped
Brass hex only
Bottom load insert Monel w/ .075” clearance inserts w/
short ball travel
Silicon Nitride, alternate pattern
Nickel Carbide, alternate pattern single lapped
316L SS
316L SS
316L SS
316L SS
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
Top Lift Sub
Barrel Couplings
Barrel
Lower Barrel Extension
Lower Coupling
Seating Nipple
TV Cage
J-55 API w/ TK-99 coated ID
2’ Lathe cut J-55 nipple w/ TK-99 coated ID
316L SS
Brass ELNI coated
18’ Lathe cut J-55 nipple w/ TK-99 coated ID
J-55 API w/ TK-99 coated ID
316L SS API
Bottom load insert Monel w/ .075” clearance inserts w/ short ball
travel
Silicon Nitride, alternate pattern
Nickel Carbide, alternate pattern single lapped
Spray Metal w/ Monel pins w/ TK-99 coated ID
316L SS
TV Ball
TV Seat
Plunger
Puller Assy
Rod Pump Best Practices
Tubing Pump
Component:
SV Fish Neck
SV Cage
Specification:
316L SS
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).
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
0.450
0.400
0.350
0.300
0.250
0.200
0.150
0.100
0.050
0.000
1999
2000
2001
2002
2003
2004
2005
Problem Well Count
Defined as any Two Failures within 365 days
120
100
80
60
40
20
0
2000
2001
2002
2003
2004
2005
Failure Index Number
“Cost per Failure x Failure Frequency”
4000
3500
3000
2500
2000
1500
1000
2001
2002
2003
2004
2005