UNDERSTANDING, ECONOMIC ANALYSIS OF & EFFICIENTLY MITIGATING DOWNHOLE FAILURES

Transcription

1 13 th Annual Sucker Rod Pumping Workshop Renaissance Hotel Oklahoma City, Oklahoma September 12 15, 2017 UNDERSTANDING, ECONOMIC ANALYSIS OF & EFFICIENTLY MITIGATING DOWNHOLE FAILURES TUBULAR LININGS ROB DAVIS, MICHAEL NAGUIB, & BILL SNIDER

2 TYPES OF DOWNHOLE CORROSION GENERAL vs. LOCALIZED CORROSION CO 2 H 2 S CHLORIDE OXYGEN MICROBIOLOGICALLY INFLUENCED (MIC) GALVANIC Sept , Sucker Rod Pumping Workshop 2

3 UNIFORM CORROSION Sept , Sucker Rod Pumping Workshop 3

4 CO 2 CORROSION Sept , Sucker Rod Pumping Workshop 4

5 H 2 S CORROSION Sept , Sucker Rod Pumping Workshop 5

6 MIC Sept , Sucker Rod Pumping Workshop 6

7 OXYGEN CORROSION Sept , Sucker Rod Pumping Workshop 7

8 CONTROLLING DOWNHOLE CORROSION METALLURGY CHEMICAL TREATMENT ORGANIC COATINGS (IPC) THERMOSET COMPOSITE (GRE) PIPE, SUCKER RODS, & TUBING LINERS THERMOPLASTIC LINERS (TPL) Sept , Sucker Rod Pumping Workshop 8

9 TYPES OF DOWNHOLE WEAR ABRASIVE ADHESIVE EROSIVE FRETTING CORROSIVE INTERFACIAL Sept , Sucker Rod Pumping Workshop 9

10 ABRASIVE WEAR Occurs when a hard rough surface slides against a softer surface Two-body wear Three-body wear Sept , Sucker Rod Pumping Workshop 10

11 ABRASIVE WEAR EXAMPLES: GOUGING GRINDING SCRATCHING POLISHING Sept , Sucker Rod Pumping Workshop 11

12 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. - Asperities - Compressive force Sept , Sucker Rod Pumping Workshop 12

13 FRETTING WEAR Repeated cyclical rubbing between two surfaces which removes material from one or both surfaces in contact 1- Cyclic contact motion 2- Material removed, oxidized. 3- Particles detach 4- Hard oxidized debris rubs against surface. Sept , Sucker Rod Pumping Workshop 13

14 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 , Sucker Rod Pumping Workshop 14

15 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 , Sucker Rod Pumping Workshop 15

16 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 , Sucker Rod Pumping Workshop 16

17 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 , Sucker Rod Pumping Workshop 17

18 Common Misconception 2 J-55, N-80, L-80 & P-110 in Sour Service N-80 and P-110 NOT acceptable for sour (H 2 S) 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 H 2 S still occur. Why? Perhaps a NEW Premier sour service J-55 with tighter requirements than API 5CT is warranted? Sept , Sucker Rod Pumping Workshop 18

19 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 CO 2 & H 2 S, chlorides present difficult & complex downhole materials selection problems. Sept , Sucker Rod Pumping Workshop 19

20 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 , Sucker Rod Pumping Workshop 20

21 Common Misconception 5 Root Cause Failure Analysis Root Cause Failure Analysis does NOT mean 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 , Sucker Rod Pumping Workshop 21

22 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 , Sucker Rod Pumping Workshop 22

23 Case Study 1 Consort, AB PC Pumped Well 8% CO 2 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, Lined Tubing Lasted 12 Years Eliminating Tubing Failures and Still Reusable Estimated Benefit of Liner in Single Well was Over $650, (at $30 per BBL Oil Price) for 12 Years Sept , Sucker Rod Pumping Workshop 23

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25 Case Study 1 Consort, AB Canada 12 Year Tubing Life PC Pumped Well Tubing Cost per Foot (USD) 6.00 Liner Cost per Foot (USD) 5.25 Oil Price per Barrel (USD) 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) 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, Sept , Sucker Rod Pumping Workshop 25

26 Comparative Monthly Operating Profit Analysis Consort Well, First 5 Years with TPL vs. Bare Tubing Sept , Sucker Rod Pumping Workshop 26

27 Consort Well Approx. $55,000 (over 3.5X Total TPL Cost) per year incremental Operating Profit Benefit Over First 5 Years Cumulative Operating Profit Sept , Sucker Rod Pumping Workshop 27

28 Consort Well Cumulative Operating Profit Improvement from TPL in First 5 Years at Total Liner Cost of Less Than $15,000 Sept , Sucker Rod Pumping Workshop 28

29 5 Year Economic Benefit of TPL in Consort PC Pumped Well Sept , Sucker Rod Pumping Workshop 29

30 Consort, AB Lined Used Tubing After 12 Years of Service in PC Pumped Well Sept , Sucker Rod Pumping Workshop 30

31 Case Study Two Wolfbone Beam Pumped Well 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 Ultratube TM Liner Installed in Well at Total Cost of Less Than $40, 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, in First 30 Months in Single Well Sept , Sucker Rod Pumping Workshop 31

32 30 Months of Service in Wolfbone Well Tubing Cost per Foot (USD) 5.00 Liner Cost per Foot (USD) Oil Price per Barrel (USD) 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) 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, Sept , Sucker Rod Pumping Workshop 32

33 Comparative Monthly Operating Profit Analysis Wolfbone Well Before vs. After TPL Installation in Single Well Over 30 Months Sept , Sucker Rod Pumping Workshop 33

34 Wolfbone Well Operating Profit Benefit of TPL Tubing in First 30 Months Sept , Sucker Rod Pumping Workshop 34

35 Single Wolfbone Well TPL Benefit Over First 30 Months of Service at Total Liner Cost of Less than $40,000 Sept , Sucker Rod Pumping Workshop 35

36 Case Study 3 Eagle Ford SRP Well 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, TPL Benefit Estimated at $220, (at $30 per BBL Oil Price) over 39 Months (Current Well Operating Life) in Single Well Sept , Sucker Rod Pumping Workshop 36

37 39 Months of Service in Eagle Ford Well Tubing Cost per Foot (USD) 5.00 Liner Cost per Foot (USD) Oil Price per Barrel (USD) 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) 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, Sept , Sucker Rod Pumping Workshop 37

38 Comparative Monthly Operating Profit Analysis Single Eagle Ford Well for 39 Months Sept , Sucker Rod Pumping Workshop 38

39 Approx. $77,000 Per Year Increase in Operating Profit in Eagle Ford Well Over First 39 Months Sept , Sucker Rod Pumping Workshop 39

40 Single Eagle Ford Well TPL Benefit Over First 39 Months of Service at Total Liner Cost of Approximately $30,000 Sept , Sucker Rod Pumping Workshop 40

41 ACKNOWLEDGEMENTS Thank You Customers of Western Falcon Co-Authors Co-Workers Sept , Sucker Rod Pumping Workshop 41

42 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 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 , Sucker Rod Pumping Workshop 42

43 Disclaimer 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, noninfringement of copyright or patent rights of others, merchantability, or fitness or suitability for any purpose. Sept , Sucker Rod Pumping Workshop 43

44 QUESTIONS Rob Davis Visit or Sept , Sucker Rod Pumping Workshop 44