understanding, economic analysis of ... annual sucker rod pumping workshop renaissance hotel...

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

UNIFORM CORROSION


CO2 CORROSION


H2S CORROSION


MIC


OXYGEN CORROSION


CONTROLLING DOWNHOLE

CORROSION

▪ METALLURGY

▪ CHEMICAL TREATMENT

▪ ORGANIC COATINGS (IPC)

▪ THERMOSET COMPOSITE (GRE) PIPE,

SUCKER RODS, & TUBING LINERS

▪ THERMOPLASTIC LINERS (TPL)


TYPES OF DOWNHOLE WEAR

▪ ABRASIVE

▪ ADHESIVE

▪ EROSIVE

▪ FRETTING

▪ CORROSIVE

▪ INTERFACIAL


ABRASIVE WEAR

Occurs when a hard rough surface slides against a softer surface


Two-body wear

Three-body wear

ABRASIVE WEAR

EXAMPLES:

▪ GOUGING

▪ GRINDING

▪ SCRATCHING

▪ POLISHING


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

FRETTING WEAR

Repeated cyclical rubbing between two

surfaces which removes material from one or

both surfaces in contact


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.


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.


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)


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


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…?


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.


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.


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


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.


Case Study 1 – Consort, AB PC

Pumped Well


▪ 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


▪ 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


Consort Well – Approx. $55,000 (over 3.5X Total

TPL Cost) per year incremental Operating Profit

Benefit Over First 5 Years


Cumulative Operating Profit

Consort Well – Cumulative Operating Profit

Improvement from TPL in First 5 Years at Total

Liner Cost of Less Than $15,000


5 Year Economic Benefit of TPL in

Consort PC Pumped Well


Consort, AB Lined Used Tubing After

12 Years of Service in PC Pumped Well


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 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






▪ Start Date 1-August-2013











▪ Base Tubing Workover Cost (USD) 95,000.00



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



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


▪ 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






▪ Start Date 1-December-2012











▪ Base Tubing Workover Cost (USD) 90,000.00


Single Eagle Ford Well for 39 Months


Approx. $77,000 Per Year Increase in Operating

Profit in Eagle Ford Well Over First 39 Months



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


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

[email protected]

Visit www.westernfalcon.com or www.polycore.ca


mailto:[email protected]

http://www.westernfalcon.com/

http://www.polycore.ca/

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