Permalink Gallery

Software Analysis – Doubles Production

Software Analysis – Doubles Production

Software Analysis of ESP Well Doubles Production
An operator had a well that had been running for three years. But, was it optimised?
 
Problem
If an ESP is running and producing, we are happy and we’ll run it until it dies. In such scenarios we can be losing many barrels of production.

 
What we did
As part of a training program, we analysed multiple wells in a field using software to identify undiagnosed problems, resulting in production loss. The biggest opportunity arose in a well that had been producing for 3 years.

The installed ESP had an operating range of 1250-2700 bbls, at the operating frequency. The well was producing 2553 bfpd, so everybody was happy. An analysis of the operating data was performed, which showed that the drawdown caused by the ESP, was half of what it should be.

The well was identified as a prime candidate for an ESP upsizing. A workover was performed and production was increased to 5503 bfpd, a water cut of 83% was maintained, as shown in the plot of production before and after.

It’s a shame the incremental production was not achieved sooner.

 
Cost Benefit Analysis
Spend = $30,000

Value = $50,150 additional dollars per days (based on $100/barrel oil).

 
Results
Production was increased from 434 to 935 barrels of oil per day, an increase of 500 barrels of oil per day.

 

See our Pump Checker software if you want to know more about how to perform this type of analysis.

 

Permalink Gallery

Contracting Strategy – USA

Contracting Strategy – USA

Change in Contracting Strategy Saves $3.75 million in 6 months
Change also drives cooperative approach to failure analysis, identifies quality issues and drives ESP equipment specification improvements
Problem
An operator was using ESPs to de-liquify a gas shale play, the wells required ESPs to produce the liquid volume for 300-600 days. However the ESP failure rate was colossal, 46% of all the ESPs installed, failed in less than 90 days, the average runlife of failed ESPs was 126 days. Every failed ESP cost the operator $250,000 to replace, just for a replacement ESP (rig cost and loss production is additional).
What we did
We performed a historical review of the ESP failures. Most of the failures had been attributed to ‘well conditions’. Changing fluid rates, increasing gas volumes, temperature and occasional issues with scale are factors that make the operating environment difficult; we did not view these ‘well conditions’ as the cause of failures.

We performed expert witness inspection of 73 failed systems and audits of the equipment providers operations identified that the majority of failures were due to equipment quality issues, poor handling during transportation, installation snafus or improper setup of the protection system for the ESP.

We challenged the equipment provider to work with us to improve runlife, as part of this we worked with them to switch from a direct purchase contract to a ‘skin in the game’ contract model. The equipment provider now receives no payment for the equipment of the equipment fails prior to 90 days, thereafter, if the equipment reaches target runlife, 110% of the cost of the equipment is paid and the supplier receives an on-going payment per month of additional runlife.
Cost Benefit Analysis
Spend = $525,529

Value = $3.75 million saving in less than […]

Permalink Gallery

Team Training – Colombia

Team Training – Colombia

Team Training Almost Doubles Production
Hupecol Operating Company LLC were operators of several small fields in Colombia, with 10 wells being produced using ESPs
Problem
Hupecol had a young, enthusiastic, intelligent staff but with little artificial lift experience. They had 10 wells with ESPS installed, but was production being lost?
What we did
A training program was prepared for the team, whereby the team were taught ESP diagnosis techniques to compare theoretical ESP performance to actual performance. Each of the team was then assigned two wells and mentored through the process of analysing the wells to come up with a list of recommendations for the wells. These recommendations were then implemented and included:

Identification of worn equipment and subsequent changeout
Upsizing to bigger ESPs more closely matched to well inflow
Frequency increases on existing systems
Improved protection using alarms and trips based on actual operating conditions

Cost Benefit Analysis
Spend  = $4613.40

Value = $119,820 additional dollars per days (based on $60/barrel oil). One hour of the additional production paid for the training.
Results
Production was increased from 2183 to 4180 barrels of oil per day, an increase of 1997 barrels of oil, almost doubling production of the 10 wells.

.
“Whenever we want to increase production, or troubleshoot our wells, we always call ALP.” – Tony Stuart, Hupecol
.

Permalink Gallery

Proper Lift Method – Colombia

Proper Lift Method – Colombia

Proper Lift Method Enhances Production
Petrominerales Colombia Ltd (PCL) had invested in the reactivation of the Orito field in Colombia. They needed to ensure that they receive maximum production for every dollar of investment. The Orito field had almost every artificial lift method, so the challenge for PCL was, what is the correct lift method for each well?
Problem
Selecting the correct lift method for the field is a challenge – particularly if the correct equipment is not available. This field and the flowrate ranges and depths means that PCPs, ESPs, rod pumps and gaslift could all be applicable for the range of well conditions – so how do you choose?
What we did
We did a review of well performance, rate, drawdown and ability to produce the well using the existing lift method. We identified that gaslift was resulting in lost production on the lower rate wells, due to compressor downtime and the inability of gaslift to create maximum production. A trial of long stroke rod pumps was proposed as a replacement for gaslift on low rate wells.
Results
The trial of long stroke rod (rotaflex) pumps was successful and rod pumps are now used in preference to gaslift. The operator has now accepted that this is the appropriate lift method for these wells.
Read more…
A paper on this information was presented at the 2007 SPE Annual Technical Conference, the paper and presentation can be downloaded. Send us an email if you want to read the full presentation.

Permalink Gallery

Fewer Failures – USA

Fewer Failures – USA

Repeat failures of rod pumps halved, saving an estimated $16 million a year
What do you do when the average production on your wells is an average of only 8 bopd? You slash costs by eliminating premature failures…
 
Problem
A large company had around 2,120 rod pumped wells with an average runlife of just over three years – but a small number of them had rod pump systems that repeatedly failed in less than six months.

Company culture was to focus on getting back into production as soon as possible – rightly so, but a step was missing. Those repeat failures were costing the company an estimated $32 million each year.

 
What we did
On any well that failed in less than one year, the engineers specifying the replacement equipment were asked the question, “Is this what you believe will give the best chance of a three year runlife?.”  Initially, the answer was “no”.

Solutions found and implemented were:

An audit of all equipment suppliers performed and equipment provider who scored highest on the audit was given the majority of the work.
Applied pump off controllers on more wells
Applied VSDs to control
Stopped reusing low cost parts
Inspected more tubing and rods and developed philosophy around when equipment should be inspected.
Lift specialists attended teardown of short runlife systems

 
Results
There was a shift in mental attitude, so the team’s focus was to operate a system capable of achieving three-year runlife. The number of systems failing each year in less than 12 months was halved.

Permalink Gallery

Increased Production – Colombia

Increased Production – Colombia

Production Increase in Colombia with New ESP System
Petrominerales Colombia Ltd (PCL) discovered the corcel field in the Llanos of Colombia. The discovery of the field had the potential to increase their production significantly. PCL desired that the well produce optimally and that the installed ESP be reliable.
Problem
This was a new well that was expected to produce around 10,000 bfpd. But, being a new well design information was scarce and local equipment inventory was limited.
What we did
Designed and specified the ESP system, developed the start-up procedure, supervised the wellsite installation and start-up, provided ongoing analysis of ESP performance.
Results
The ESP system installed in the corcel-1 well ran for the longest runlife of any ESP field installed in the corcel field.

Permalink Gallery

Production Increase – North Sea

Production Increase – North Sea

$1.35 million potential increase in daily production identified
Combination of gaslift and ESPs in the North sea creates significant gains
 
Problem
Our client had taken over a number of assets in the North Sea and wanted to increase production. The wells in the fields were all still on natural flow. They needed to define the benefit of introducing artificial lift.

 
What we did
All the wells were modelled, using prosper, to define the capability of the existing wells. The benefit of implementing gaslift vs ESPs on the wells was then predicted and compared.

A combination of poorboy gaslift and ESPs was recommended because of limited gas availability and electrical power limitations. We identified total production gains of 22,500 bopd.

 
Cost benefit analysis
Spend – $12,000

Value – $1.35 million additional dollars per day (based on $60/barrel oil)

 
Results
Increased production potential of 22,500 bopd

Permalink Gallery

ESP Training – Ecuador

ESP Training – Ecuador

$5 million in lost production identified
ESP training and mentoring in Ecuador finds 67 improvements in software, improving runlife of equipment and increasing skill levels of personnel
Problem
Our client had an ESP population of around 100 and was in the process of implementing a new software tool to help with real-time monitoring and diagnosis of their performance. It had already been introduced in other locations with rod pumped wells but had not previously been used for ESPs. The operations manager knew his staff needed help and hired us to deliver training (in Spanish) and review how the software performed ESP analysis.
What we did
We ran two one-week courses for their staff, supplemented by a mentoring programme focusing on use of the software to diagnose ESP problems that were resulting in lost production. Each person was given wells to analyse and required to review their work with the trainer.

We analysed how the software was performing ESP diagnosis and found 67 suggested improvements, which were implemented for the global software deployment.

We then worked with the operator staff and ESP supplier to review and improve all aspects of the ESP cycle, resulting in improved runlife of the equipment and improved competency of operator personnel in management of ESP operations.
Cost benefit analysis
Spend – $183,000

Value – $5 million
Results
Approximately $5 million of lost production, as a consequence of ESP issues, was diagnosed as a result of the mentoring process.
Read More
Email us for additional information: Beyond Automation – ESP Optimisation and Runlife Improvement Process in Occidental Ecuador, a paper on this project that we presented at the ESP workshop in Houston 2005.

.
“The training and consultancy that ALP offers is highly specialised. Very few people in our industry have the ability and experience to provide […]

Permalink Gallery

More Oil – Colombia

More Oil – Colombia

More oil – 3400 bopd
Failure analysis, new equipment specification and diagnosis techniques deliver ability to identify and prevent a production loss of 3,400 barrels a day
Problem
Canacol Energy’s Rancho Hermosa field, had been slowly losing production on their existing wells, then two ESPs failed resulting in a significant production drop – a big problem for a small company that had recently invested in the field and had ambitions for major growth. They asked us to do a failure analysis on the two failed ESPs wells, to find out what was going wrong.
What we did
A lot more than a simple teardown. We performed a review of the production history and ESP operating data of their wells and using advanced diagnosis techniques, quickly identified that Canacol were taking big hits on their production, because the ESP pumps were wearing out due to solids. We identified when the production losses started, quantified the value of the lost production and demonstrated the value of proactive workovers. One well alone had lost an estimated 63,985 barrels of oil over the ‘wear’ period until the ESP failed. The teardowns of the failed equipment sets substantiated the pump wear conclusion (See photo).

Comparison of worn out pump impeller vs. new pump impeller

A specification for Canacol’s ESP equipment was provided, so that the equipment could withstand the production of fine solids and mitigate wear
Cost Benefit Analysis
Spend  = $18,462.94

Value =  $222,000 additional per day
Results
Production rose by 3,400 barrels of oil a day after the two down failed ESPs were replaced. A technical solution to prevent pump wear was provided and a methodology to diagnose and quantify lost production was introduced, so that pumps can be proactively replaced when production is being lost.

.
“This was a really […]