Case study: Italy

Production Solution saves biodiverseregion operator $4 million by removing
scale, eliminating workover costs
To improve production from an oil
well in an environmentally sensitive
national forest, a customer in southern
Italy installed electrical submersible
pumps (ESPs) in an area known for scale
deposition. The customer installed one
upper and one lower ESP to serve as aredundant system in case one of theESPs became clogged.
As part of the overall plan, the customer
treated the well with a Baker Hughes
scale inhibitor. By injecting the scaleinhibitor continuously through a
dedicated capillary tubing line, thecustomer hoped to prevent carbonate
scale with a presence of discrete
sulphate deposition.

The downsides ofconventional operations

The conventional option involved theacidification of both the ESPs andwellbore—a common practice incarbonate wells and a method thecustomer had already performed inother wells in the field. But, due to thelocation of the well in a biodiverse
area, the potential health, safety andenvironmental (HSE) risks were too high.
Additionally, the requirement to take theESPs offline for the acid treatment would
have a significant, negative impact
on production.
The customer asked Baker Hughes for analternative that would keep the ESPs in
operation and avoid workover costs.

The promise ofProduction Solution

First stage of ESP with accumulation of scaleat the impeller.

The ESP intake and discharge pressuresremained stable for five months and thewell produced 8,000 BOPD (1271 m3/d)
with only a 2% water cut. In the sixth
month, however, the pressure began
to rise approximately 7 psi (0.5 bar)
per day, reducing the ESP dischargepressure. Without any intervention, thecustomer would have had to shut down
both the upper and lower ESPs to avoid
pump blockage, decreasing the overall
production rate.

A Baker Hughes Production Solution
team studied the data acquired fromthe company's ProductionLink™ Expert
artificial lift monitoring service andanalyzed a pulled ESP that had been
deployed in the field previously todetermine the root cause. The teamconcluded that, despite the current
chemical injection regimen, the 50%
increase in the production fluid’s water
cut had accelerated the scale deposition.

Challenges• Maintain production despite ESPsclogged with scale• Minimize risk of future premature
ESP system failures• Avoid potential impact ofworkover operations in anational parkResults• Restored production to originallevels without taking ESPs offline• Saved an estimated$4 million USD in avoided
workover costs• Mitigated possible contamination
in a national forest• Developed precise chemical
regimen to use in additional wells
to curtail scale buildup in ESPs
• Experienced no HSE issues or
nonproductive time (NPT)With an eye to keeping costs low andavoiding potentially damaging workover
operations in the forest, Baker Hughes
engineers suggested overdosing thewellbore with the existing scale inhibitor.
Field personnel increased the scale
inhibitor injection from 80 to 300 ppm
for a period of 30 days. While the motor
amperage rose, it was still not enough to
restore the ESPs to optimum operating
conditions.
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Drawing on its expertise, the Production
Solution team devised a new, more
effective chemical treatment. To remove
the scale in both pumps, the teamsuggested replacing the scale inhibitorwith an environmentally friendly Baker
Hughes scale dissolver. This scaledissolver specifically attacks barium
sulphate scale in oilfield equipment
and provides excellent scale dissolution
under alkaline conditions like those inthis field.
The customer agreed to theBaker Hughes proposal and theteam implemented the strategy. The
substitution of the scale inhibitor with thescale dissolver began at a rate of 460 L/d(121.5 gal/day). Over the next five months,
the scale dissolver effectively dissolved
the sulphate and carbonate deposits,
restabilizing the ESP parameters andfluids production to the original levels.
The treatment proved so effective thatthe team gradually reduced the dosage
from the initial injection down to 240 L/d(63.4 gal/day).

treatment. The continuous injection of
the scale dissolver through the downhole
injection line below the ESP intakes
increased the individual and overall
ESP run life. As a result of the chemicaltreatment, both ESPs ran for a combined
1,108 days.

The Production Solution team optimized
the quantity of the scale dissolver
necessary to maintain the ESPs in thebest possible running condition. With theprecise amounts isolated, the customer
would be able to switch to the scaleinhibitor from the scale dissolver andback again as well conditions dictated.

With the increase in the ESP run lives, thecustomer eliminated the approximately$4 million USD cost and environmental
impact of workover operations in thebiodiverse region. By reducing thenumber of coiled tubing activities
needed to treat the wells, theBaker Hughes Production Solution had apositive impact on the customer’s overall
HSE rating. The customer was also able totake the predictable performance of thischemical regimen and apply the bestpractices to other wells in the field.

The predictable performanceof Production Solution

The innovative Baker Hughes Production
Solution avoided ESP shutdowns,
enabling the pumps to operatecontinuously during the chemical

The quantity of total liquidand quantity of oil gradually
decreased because of scaling.
After the implementationof the scale dissolver, oil
production returned tooptimal levels.

Over the course of fivemonths, the effectiveness ofthe scale dissolver proved
itself, enabling a gradualreduction of the amountneeded to maintain ideal ESP
operational parameters, aprogram the customer would
use for future wells.

Copyright 2021 Baker Hughes Company. All rights reserved. 83393 Rev. 02/2022

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