Project 310 PP

8/2/2019 Project 310 PP

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Prepared By:

Kolton Chapman, Petroleum Engineering Technology Student

Prepared For:

Craig Sinclair, Manager Tupper Operations, Murphy Oil Company Ltd.

& Anthony Wallace, Petroleum Engineering Technology Instructor

Artificial Lift ProductionEvaluation and Optimization on

Gas Wells

http://images.google.ca/imgres?imgurl=http://www.weblo.com/asset_images/large/Murphy_Oil_Corporation_4720cf137b299.gif&imgrefurl=http://www.weblo.com/asset_image/474211/98097/Murphy_Oil_Corporation/&usg=__XXC-ZW1QBI5wcUEdffpnq-8F-U4=&h=600&w=600&sz=42&hl=en&start=4&um=1&itbs=1&tbnid=XLrVz7-6sOOHLM:&tbnh=135&tbnw=135&prev=/images?q=murphy+oil+company&um=1&hl=en&tbs=isch:1

8/2/2019 Project 310 PP


Agenda1) Background2) Introduction

3) Tupper GGS SCADASystem

4) Intermitter Graph (WellB)

5) BJ Services (BakerHughes)

6)Weighted FoamerDecline Curve

7) Tundra PetroleumServices

8) Plunger Lift Explanation

9) Production Control

10) PCS Quotes &Economics

11) Premier IntegratedTechnologies

12) PIT Quotes &Economics

13) Tupper Field Feedback

14) PIT Plunger DeclineCurve

15) PCS Plunger DeclineCurve (G Well)

16) Conclusion

17) Recommendations

18) Question Period



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Background Murphy Oil Company Ltd. (MOCL) appointed Mr.

Craig Sinclair as my mentor for this project. Craigis an experienced Chemical EngineeringTechnologist, R.E.T. and is Manager of Tupper

Operations The field analyzed is the Tupper field located in

North Eastern British Columbia South of DawsonCreek

This field was purchased by MOCL in 2007 fromBear Ridge Resources, and the first day ofproduction out of this field was December of 2008

The Tupper field produces shale gas



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Introduction To determine the best approach for Murphy Oil

Company Ltd. towards installing artificial lift inseven currently liquid loaded gas wells

Analyzed based upon simple economics,attainable production rates, maintenance costs,and installation costs

MOCL Approved Service Companies/

Control System

Artificial Lift Application

Capillary String Foamer Plunger Intermitter

BJ Services (Baker Hughes) x Tundra Petroleum Services x

Production Control Services x

Premier Integrated Technologies x

Tupper GGS SCADA System x




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Tupper GGS SCADA System• The systems full name is “Tupper Gas Gathering System

Supervisory Control and Data Acquisition System”

• The Tupper GGS SCADA System controls the entireTupper field and plant

• The operator can enable or disable an “Intermitter timer”

which closes and opens the flow choke, therefore havingthe ability to shut-in the well and build formation pressure














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Intermitter Graph (Well B)



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BJ Services (Baker Hughes) The company has last conducted water sampling out

of the producing formation on July 7, 2009. The watersamples were analyzed using a “Foam Blender Test”

and “Foam Tower Test”

Foamer

Supplier Product Cost

($/L FOB)

Initial

Batch Cost

(25 L)

Daily

Operating Cost

($/day)

Monthly

Operating Cost

($/month)

Comments

BJ Services

(Baker Hughes) $ 5.75 $ 143.75 $ 57.50 $ 1750.15

No noticeable production

increase yet shut in times

slightly reduced.











































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Weighted Foamer DeclineCurve

It was suspected that this batching was unsuccessful due to theinability to get the foamer through the high level of liquid in thewell, therefore MOCL did not proceed to inject foamer into any

wells









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Tundra Petroleum Services Tundra Petroleum Services is a Western

Canadian based capillary tubing service company

Capillary String Quote Unit cost Unit Amount Total

Line Cost ($/meter) $ 7.50 2785m $21,037.50

Mileage- Capillary Unit ($/km) $ 3.75 700 km $2,625.00

Mileage- Support Pickup ($/km) $ 1.25 700 km $1,085.00

Capillary Hanger w/ Injection Control Valve n/a n/a $2,350.00

Set Up/Installation Charge n/a n/a $2,445.00

Surface Equipment n/a n/a $7,150.00

Well A: Total Estimated Cost $ 37,192.50

Well

Prod.Volume

Prior To

Capillary

String

(e3m³/d)

ExpectedProd.

Volume

After

Install

(e3m³/d)

Expected

Prod.

Volume

Increase

(e3m³/d)

Capital Cost

(Including Cap.

String and initial

foamer batch of

25L)

Operating Cost

($/d)

Expecting

injection rate of

10L/d

Application

Payback

Period

(days)

A 10 16 6 $37,336.25 $ 57.50 45.8











































































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Plunger Lift Explanation Plunger lift technology is a type of artificial lift

(AFL) that is very accepted in the oil and gasindustry because it only uses the wells natural

energy to help lift fluids out of the wellbore rather

than an external power source

http://www.fergusonbeauregard.com/downloads/Introduction_to_Plunger_Lift.pdf













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Production Control Services(PCS) Data Sheets filled out and sent to PCS

Plunger lift evaluation completed by PCS using:Fekete Virtuwell Software, and Foss & GaulEquations

Once calculations completed PCS produced aconventional plunger recommendation for eachwell stating : whether a plunger lift candidate ornot, size of plunger to be used, and cycle times


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PCS Quotes & Economics

Actual Conventional 63.0mm Plunger Quote Unit cost

Swabbing Cost $ 3,100.00 Standard Plunger Lift Components $ 7,555.50

Service Charges & Installation Estimate $ 2,500.00

Estimated Total $ 13,155.50

Actual Conventional 73.0mm Plunger Quote Unit cost

Swabbing Cost $ 3,100.00

Standard Plunger Lift Components $ 11,127.25



Well

Prod.

Volume

Prior To

Plunger

Lift

(e3m³/d)

Expected

Prod.

Volume

After

Install

(e3m³/d)

Expected

Prod.

Volume

Increase(e3m³/d)

Capital Cost

($)

Operating Cost ($/d)

*Expecting

replacement due to

solids wear in 2years

Application

Payback

Period

(days)

A 10 14 4 $ 13,155.50 $ 18.00 24.4

B 11 15 4 $ 13,155.50 $ 18.00 24.4

C 11 16 5 $ 13,155.50 $ 18.00 19.4

D 11 14 3 $ 16,727.25 $ 22.89 41.9

E 24 26 2 $ 13,155.50 $ 18.00 50.8

F 19 21 2 $ 13,155.50 $ 18.00 50.8

G 10 12 3 $ 13,155.50 $ 18.00 33.1


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Premier IntegratedTechnologies Premier Integrated Technologies (PIT) is the only

Canadian provider of the Pacemaker Plunger Lifttechnology

The Pacemaker plunger is a two piece plunger

Pacemaker plunger technology allows continuousgas flow rates from wellhead to plant inlet, whichcreates less problems regarding gas processing

http://www.mgmwellservice.com/images/variety-new.jpg







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PIT Quotes & Economics

Actual Pacemaker Technology 63.0mm

Plunger Quote Unit cost

Swabbing Cost $ 3,100.00 Standard Plunger Lift Components $ 9,022.00



Actual Conventional 73.0mm Plunger Quote Unit cost Swabbing Cost $ 3,100.00

Standard Plunger Lift Components $ 6,336.90



Well

Location

Prod.

Volume

Prior To

Plunger

Lift

(e3m³/d)

Expected

Prod.

Volume

After

Install

(e3m³/d)

Expected

Prod.

Volume

Increase(e3m³/d)

Capital Cost

($)

Operating Cost ($/d)

*Expecting

replacement due to

solids wear in 2years

Application

Payback

Period

(days)

A 10 14 4 $ 14,822.00 $ 20.29 27.4

B 11 15 4 $ 14,822.00 $ 20.29 27.4

C 11 16 5 $ 14,822.00 $ 20.29 22.0

D 11 14 3 $ 12,136.90 $ 16.61 30.6

E 24 26 2 $ 14,822.00 $ 20.29 57.7

F 19 21 2 $ 14,822.00 $ 20.29 57.7

G 10 12 3 $ 14,822.00 $ 20.29 37.4


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Tupper Field Feedback In the past year there has been three plunger lift

applications installed in the Tupper field

Two PIT Pacemaker plungers & one PCSconventional plunger

During the evaluation of report the Tupper fieldexperienced salt precipitation (halite) occurring ina few producing wells


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PIT Plunger Decline Curve

Plunger Lift

Applied

Intermitter Enabled


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PCS Plunger Decline Curve

Intermitter Enabled Plunger Installed


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Conclusions

Premier Integrated Technologies Pacemaker technology is thebest solution for removing liquid loading due to the Tupper fieldspast experiences with this technology installed on wells that areno longer able to flow on intermitters

Capillary Strings are very expensive compared to plunger lift,therefore making this application not as economical as plunger

lift technology. Further weighted foamer analysis needs to takeplace before this AFL application is considered, which will allow abetter understanding towards achievable production rates whenusing capillary strings

Production Control Services does not sell Pacemaker PlungerLift Technology, which allows a well to flow 24 hours a daytherefore allowing less pipeline, and gas processing problems.

Also PIT’s conventional plungers are more economical for Murphy Oil Company than the PCS’s conventional plunger applications

Weighted foamer is currently not a solution for unloading liquidloaded gas wells in the Tupper Field



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Recommendations After analysis has been completed it is concurred thatthere is no single artificial lift option that can solve every

liquid loaded well problem in the Tupper field. It isrecommended that liquid loaded wells that flow less than10 E3m³/d, should immediately have an intermitter timerenabled to increase daily gas production. Once a well is

experiencing serious liquid loading to the point that anintermitter is not effective at keeping it flowing; PITPacemaker plunger technology should be installed if thewell meets all criteria. If the well doesn’t meet Pacemaker plunger lift criteria I recommend installing a PITconventional plunger application. Plunger lift will help with

future salt precipitation in the majority of the tubing, yet it isnot a completely effective solution. I don’t recommendusing the BJ RCI 08025W weighted foamer again in theTupper field, because in the past it has not removed anyliquid loading due to high liquid columns in the wellbore.





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Question Period


Documents

Project 310 PP