08-03-15 muth pump

Muth Pump LLC

•

Extending Downhole Rod Pump Run Life 300% Using

New Technology.

07-13-15Muth Pump LLC 1

Mark Meza

&

Garold Muth

Conventional Plunger From a Well With

Sand Present


Conventional APIPlunger



60 Thousandths

Connector

Plunger Walls

2 Thousandths

Pull Rod


Funnel

The Funnel Effect

Sand and/or Solids are being

forced down and outward into

the gap due to the shape of the

standard API connector.


Wedge

When Sand or Solids are present

and you are using a POC’s with a

conventional plunger you will likely

get stuck due to the wedge effect.

The Wedge Effect


Conventional “FARR”

From

To



.060.002

97 %Reduction



.060.002

Funnel



.060.002

Wedge

07-13-15 Muth Pump LLC 16

Extending Downhole Pump Run Life using Ingenuity Innovation and New Technology Lead to

Reduced OPEX and Increased Revenue in the Duri Steam Flood (DSF), Indonesia.

SPE-145249-PP

In DSF, > 700 Pump Stuck (PS) jobs are performed each year which primarily caused by sand production. Annual total cost of this routine

service work is multimillion dollar. In addition, with average of 3 days downtime/PS job, there is over 2,100 days of lost production associated

with downtime. With currently over 5,000 active producer wells, identifying artificial lift SRP alternatives that can improve run life and reduce

number of PS jobs performed would result in lower OPEX (*Operating Expense) (less PS jobs), higher production (reduced downtime), and

lower risk of HES (*Health, Environment, Safety) incidents (less rig work).

Three viable options were identified for a field trial after soliciting ideas and opinions from Service Suppliers, MSS (*Maintenance Supports &

Services) Team, and Chevron Global Network to overcome these pump stuck issue:

0.015" fit Tubing Pump

Stroke-Thru Pump

0.002" fit FARR Plunger

The 2008-2009 PMT (*Production Management Team) HOOU (*Heavy Oil Operation Unit) Artificial Lift Lean Sigma confirmed that these

artificial lift options had a longer run life than the standard 0.010" fit pump. Average run life was increased by 93 days, and 70% of the time

produced a longer run life. During 12 months trial period, there was an average reduction of 12 PS jobs/month compared to baseline data.

Since the 0.002" fit FARR Plunger had encouraging results in low wellhead temperature wells, there was initiative to evaluate it in higher

temperature by modifying the pump fit to 0.005" considering thermal expansion. In 2010, 15 units of 0.005" fit FARR plungers were tested,

replacing either a Stroke-Thru or 0.015" Fit Pump that had failed. The results were encouraging and indicated that the 0.005" FARR Plunger

exceeded the run life of the previous pump 71% of the time with additional incremental run life of 44 days.

Author

Aan Akhmad Prayoga

Petroleum Engineer

PT Chevron Pacific Indonesia

Abstract Submitted for APOGCE 2011


In January 2013 a prominent

Kern County Oil Company (Aera)

completed a Six Sigma Study of the

FARR Plunger. The study found that

the FARR Plunger increased run

times 300% in their oil wells

equipped with FARR Plungers.

All of these wells had high

concentrations of sand and failure

rates due to sand. This study

compared the FARR Plunger to other

“Sand Pump Plungers” (Sand Pro),

(3-Tube), (-10 Conventional), (Sand

Flush) and etc.


Six Sigma Study

Plunger Count Failed % Still Running

Farr 188 94 50.00%

Non Farr* 205 182 11.22%

Significance:

• 50% of all Farr plungers are still running.

• Only 11.22% of all Non-Farr* plungers are still running.

• The large percent of Farr plungers still running requires that

we rely on the projected median runtime in the survival plot

analysis to explain the data.

2015 Coalinga Study Data Overview

*The study only looks at wells that have had a Farr plunger in them. Only two Non-Farr pump pulls prior to the Farr being installed and any Non-

Farr pump pulls after the Farr was pulled were included in the study. The Non-Farr category includes a variety of plunger types. This applies to all

slides pertaining to the 2015 Coalinga Study.

07-13-1521Muth Pump LLC

Muth Pump LLC

Non-FarrFarrCombined

Non-FarrFarrCombined

--- Non-Farr--- Farr

The projected median runtime

for Farr is 470 days.

The projected median runtime

for Non-Farr is 217 days.

The Farr has a 216% longer

projected median runtime

than the Non-Farr.

This is a 116% improvement.

2015 Coalinga Study

Survival Plot

7-13-15 22

Scenario:

If 100 Non-Farr plungers are replaced with Farr

plungers in one year, then there would be a total

yearly savings of $874,368.

2015 Coalinga StudyEconomic Analysis

Savings/well/year

$8,744

Cost/pull Projected median runtime Cost/well/day Cost/well/year

Farr $10,400 470 days $22 $8,077

Non-Farr $10,000 217 days $46 $16,820

237-13-15

Muth Pump LLC


Increase Pump Life 3-6 Times Longer

Studies in California, Indonesia, and Venezuela have all

shown the FARR Plunger out-performs other rod pump

plungers. Increasing run life an average of 3-6 times.

Reduce Environmental Spill Incidents

There is an increased risk for a spill or an accident every time you have to pull a

pump from a well. Sometimes when a pump is stuck you have to pull the whole

tubing string to retrieve the pump and get the well operational again. This could

result in costly spills or other problems. Spills could prompt a visit from the

EPA.


Reduce Health & Safety Incidents

Most oilfield accidents occur when you have rigs or other work over equipment

on site. You have more personnel in the area and a greater risk for injury.

Because the FARR Plunger will keep your pumps in the ground longer there will

be fewer well pulling’s which reduces the risk for injury.


BY MAKING ONE SMALL CHANGE TO YOUR STANDARD

API DOWN HOLE ROD PUMPS, YOU WILL:

MAXIMIZE PRODUCTION AND EFFICIENCY

MINIMIZE HEALTH, SAFETY,

& ENVIRONMENTAL RISKS

INCREASE PUMP RUN LIFE

Reduce well pulling

Reduce pump repairs

Save thousands of $dollars$ in the long run


08-03-15 muth pump

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