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13th Annual Sucker Rod Pumping
WorkshopRenaissance Hotel
Oklahoma City, Oklahoma
September 12 – 15, 2017
UNDERSTANDING, ECONOMIC
ANALYSIS OF & EFFICIENTLY
MITIGATING DOWNHOLE FAILURES
ROB DAVIS, MICHAEL NAGUIB, & BILL SNIDER
TUBULAR LININGS
TYPES OF DOWNHOLE CORROSION
GENERAL vs. LOCALIZED CORROSION
▪ CO2
▪ H2S
▪ CHLORIDE
▪ OXYGEN
▪ MICROBIOLOGICALLY INFLUENCED (MIC)
▪ GALVANIC
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 2
CONTROLLING DOWNHOLE
CORROSION
▪ METALLURGY
▪ CHEMICAL TREATMENT
▪ ORGANIC COATINGS (IPC)
▪ THERMOSET COMPOSITE (GRE) PIPE,
SUCKER RODS, & TUBING LINERS
▪ THERMOPLASTIC LINERS (TPL)
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 8
TYPES OF DOWNHOLE WEAR
▪ ABRASIVE
▪ ADHESIVE
▪ EROSIVE
▪ FRETTING
▪ CORROSIVE
▪ INTERFACIAL
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 9
ABRASIVE WEAR
Occurs when a hard rough surface slides against a softer surface
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 10
Two-body wear
Three-body wear
ABRASIVE WEAR
EXAMPLES:
▪ GOUGING
▪ GRINDING
▪ SCRATCHING
▪ POLISHING
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 11
ADHESIVE WEAR
Found between surfaces during frictional contact
and generally refers to unwanted displacement
and attachment of wear debris.
Involves material transfer from one to another.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 12
- Asperities
- Compressive force
FRETTING WEAR
Repeated cyclical rubbing between two
surfaces which removes material from one or
both surfaces in contact
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 13
1- Cyclic contact
motion
3- Particles detach
2- Material
removed, oxidized.
4- Hard oxidized
debris rubs against
surface.
EROSIVE WEAR
The impingement of solid particles or small drops of liquid or gas on a solid surface.
The impacting particles gradually remove material from the surface through repeated deformations and cutting actions.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 14
CORROSIVE AND OXIDATIVE WEAR
Chemical reaction between the worn material and the corroding medium.
Corrosive wear happens when a chemical reaction forms a thin surface film which is removed through wear. The film is then replaced and worn away again.
Oxidative wear is a similar process that occurs on unlubricated metal surfaces rubbing in air or oxygen. The main difference between corrosive and oxidative wear is that the oxidative wear oxide particles mix with metal and form a debris layer.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 15
CONTROLLING DOWNHOLE WEAR
(EMPHASIS – ROD ON TUBING)
▪ Sucker Rod Guides
▪ Rod Rotators
▪ Tubing Rotators
▪ Tubing Anchors
▪ Spray Metal (SM) Sucker Rod Couplings
▪ Roller Sucker Rod Guides
▪ Continuous Sucker Rod Strings
▪ Coatings and Metal Surface Treatments
▪ Thermoplastic Tubing Liners (TPL)
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 16
Common Misconception 1 – Classification
of Service-Induced Tubing Defects
▪ Internal vs. External Defects▪ “Pitting” vs. “Wear” shaped defects▪ EMI and UT inspections commonly utilize
multiple techniques to find different types of service-induced defects
▪ Very dependent on operator proficiency and attentiveness, calibration of equipment, and proper prove-up of defects
▪ Pressure Testing in addition to EMI inspection recommended in many cases
▪ Accuracy of wellhead vs. rack tubular inspection
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 17
Common Misconception 2 – J-55,
N-80, L-80 & P-110 in Sour Service
▪ N-80 and P-110 NOT acceptable for sour (H2S) service
▪ L-80 is hardness tested (by heat) and acceptable for sour service per NACE MR0175
▪ Although J-55 is acceptable for sour service, FAILURES due to H2S still occur. Why?
▪ Perhaps a NEW “Premier” sour service J-55 with tighter requirements than API 5CT is warranted…?
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 18
Common Misconception 3 – Chloride
Concentration vs. Corrosion Rate
▪ Corrosion Rate of saturated ( approx. 36 g NaCl per 100 g of water) salt water at room temperature on mild steel is only 16 mpy (over 13 years before 2 7/8 is breached)
▪ Corrosion Rate of 3% NaCl at same conditions is 71 mpy (approx. 3 years before 2 7/8-inch is breached).
▪ When combined with CO2 & H2S, chlorides present difficult & complex downhole materials selection problems.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 19
Common Misconception 4 – Representative
Wear Tests to Simulate Downhole Failures
▪ Taber Abrasion (ISO 9352) testing of nonmetallics at room temperature in air with weighted sandpaper wheel.
▪ Nonmetallic material properties change significantly in multiphase downhole environments as a function of the composition of the gas, hydrocarbons and aqueous phases, temperature, pressure, etc.
▪ Brittle (thermoset) materials often fail from impact, loss of adhesion, and/or erosive wear and are unable to protect the substrate from abrasive wear when they are removed.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 20
Common Misconception 5 – “Root
Cause Failure Analysis”
▪ “Root Cause Failure Analysis” does NOTmean that one single corrosive, mechanical, or wear mechanism is the reason for a downhole failure.
▪ Solving only one of the causes of a failure when multiple mechanisms combine to cause the failure probably will NOT yield an acceptable improvement in MTBF.
▪ Example – Corrosive Wear caused by sucker rods in high water cut corrosive well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 21
Common Misconception 6 – Ineffective
Application of Corrosion Inhibitors to Prevent
Rod on Tubing Wear Failures
▪ Rod on Tubing friction removes the passive
corrosion product film on tubing ID and sucker
rod.
▪ Bond of filming amine corrosion inhibitors is
NOT stronger than corrosion product to steel
▪ Filming amine corrosion inhibitors can
effectively extend sucker rod and tubing life
by protecting them from corrosion.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 22
Case Study 1 – Consort, AB PC
Pumped Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 23
▪ 8% CO2 and Over 95% Water Cut
▪ Well MTBF increased from 7 Months (tubing) with anchors, dampeners and rod centralizers to 25 Months (avg. pump life) with TPL Tubing
▪ Lined Green Band (Up To 50% Wall Loss) Used Tubing at Final Cost Below New Replacement Bare Tubing
▪ Total Liner Cost Less Than $15,000.00
▪ Lined Tubing Lasted 12 Years Eliminating Tubing Failures and Still Reusable
▪ Estimated Benefit of Liner in Single Well was Over $650,000.00 (at $30 per BBL Oil Price) for 12 Years
Case Study 1 – Consort, AB Canada
12 Year Tubing Life – PC Pumped Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 25
▪ Tubing Cost per Foot (USD) 6.00
▪ Liner Cost per Foot (USD) 5.25
▪ Oil Price per Barrel (USD) 30.00
▪ Gas Price per MCF (USD) 2.10
▪ Start Date 15-May-2002
▪ Evaluation Period (Months) 60
▪ Tubing String Depth (ft.) 2,800
▪ Oil Production Rate (BPD) 40
▪ Gas Production Rate (mcf/d) 4
▪ Lifting Cost per Barrel (USD) 10.00
▪ Average Annual Production Decline (Percent) 4
▪ Previous Workover Frequency (Months) 7
▪ Lost Production Days per Workover 5
▪ Percent of Tubing String Replaced per Workover 20
▪ New Workover Frequency for Pumps (Months) 25
▪ Base Workover Cost (USD) 40,000.00
Comparative Monthly Operating Profit Analysis –
Consort Well, First 5 Years with TPL vs. Bare Tubing
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 26
Consort Well – Approx. $55,000 (over 3.5X Total
TPL Cost) per year incremental Operating Profit
Benefit Over First 5 Years
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 27
Cumulative Operating Profit
Consort Well – Cumulative Operating Profit
Improvement from TPL in First 5 Years at Total
Liner Cost of Less Than $15,000
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 28
5 Year Economic Benefit of TPL in
Consort PC Pumped Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 29
Consort, AB Lined Used Tubing After
12 Years of Service in PC Pumped Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 30
Case Study Two – Wolfbone Beam
Pumped Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 31
▪ Well Not Profitable to operate with depressed oil price
▪ Averaging Over $30,000 Per Month in Workover Costs
▪ Using Rod Guides, Well Failed (tubing) Every 3 Months
▪ 2,600 Feet of UltratubeTM Liner Installed in Well at Total Cost of Less Than $40,000.00
▪ Failure Frequency (For Pump) Increased to 26 Months
▪ TPL Tubing Made Well Profitable to Operate at $40 per BBL.
▪ Estimated Benefit of TPL was Over $400,000.00 in First 30 Months in Single Well
30 Months of Service in Wolfbone Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 32
▪ Tubing Cost per Foot (USD) 5.00
▪ Liner Cost per Foot (USD) 15.15
▪ Oil Price per Barrel (USD) 40.00
▪ Gas Price per MCF (USD) 2.10
▪ Start Date 1-August-2013
▪ Evaluation Period (Months) 30
▪ Tubing String Depth (ft.) 12,000
▪ Oil Production Rate (BPD) 50
▪ Gas Production Rate (mcf/d) 90
▪ Lifting Cost per Barrel (USD) 25.00
▪ Average Annual Production Decline (Percent) 6
▪ Previous Workover Frequency (Months) 3
▪ Lost Production Days per Workover 3
▪ Percent of Tubing String Replaced per Workover 15
▪ New Workover Frequency for Pumps (Months) 26
▪ Base Tubing Workover Cost (USD) 95,000.00
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 33
Comparative Monthly Operating Profit Analysis –
Wolfbone Well Before vs. After TPL Installation in Single
Well Over 30 Months
Wolfbone Well Operating Profit Benefit
of TPL Tubing in First 30 Months
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 34
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 35
Single Wolfbone Well TPL Benefit Over First 30 Months
of Service at Total Liner Cost of Less than $40,000
Case Study 3 – Eagle Ford SRP Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 36
▪ Well MTBF Increased from 12 Months
(Using Molded Rod Guides) to Life of Pump
(22 Months) with TPL Tubing in Bottom
2,000 Feet of Well
▪ Total TPL Cost Approx. $30,000.00
▪ TPL Benefit Estimated at $220,000.00 (at
$30 per BBL Oil Price) over 39 Months
(Current Well Operating Life) in Single Well
39 Months of Service in Eagle Ford
Well
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 37
▪ Tubing Cost per Foot (USD) 5.00
▪ Liner Cost per Foot (USD) 15.15
▪ Oil Price per Barrel (USD) 30.00
▪ Gas Price per MCF (USD) 2.10
▪ Start Date 1-December-2012
▪ Evaluation Period (Months) 39
▪ Tubing String Depth (ft.) 9,850
▪ Oil Production Rate (BPD) 200
▪ Gas Production Rate (mcf/d) 150
▪ Lifting Cost per Barrel (USD) 13.00
▪ Average Annual Production Decline (Percent) 5
▪ Previous Workover Frequency (Months) 12
▪ Lost Production Days per Workover 4
▪ Percent of Tubing String Replaced per Workover 10
▪ New Workover Frequency for Pumps (Months) 22
▪ Base Tubing Workover Cost (USD) 90,000.00
Comparative Monthly Operating Profit Analysis –
Single Eagle Ford Well for 39 Months
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 38
Approx. $77,000 Per Year Increase in Operating
Profit in Eagle Ford Well Over First 39 Months
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 39
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 40
Single Eagle Ford Well TPL Benefit Over First 39 Months
of Service at Total Liner Cost of Approximately $30,000
ACKNOWLEDGEMENTS
Thank You
▪ Customers of Western Falcon
▪ Co-Authors
▪ Co-Workers
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 41
Copyright
42
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 use of this presentation is prohibited without the expressed written permission of the author(s). The owner company(ies) and/or author(s) may publish this material in other journals or magazines if they refer to the Sucker Rod Pumping Workshop where it was first presented.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop
Disclaimer
43
The 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.
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop
QUESTIONS
Rob Davis
+1-832-391-9454
Visit www.westernfalcon.com or www.polycore.ca
Sept. 12-15, 2017 2017 Sucker Rod Pumping Workshop 44