Extremely Abrasive Colombia Well Produces for 797 Days with a Rugged Maximus ESP System | Schlumberger
Case Study
Llanos Orientales Basin, Colombia, South America, Onshore

Challenge: Minimize the intervention frequency and choked production related to ESP erosion failures in wells with high solids production.


  • Install robust REDA Maximus ESP system with 5530 alloy stage metallurgy, tungsten carbide full bearing housing (FBH), and keyless bearing sleeves
  • Optimize pump frequency on startup and monitor performance to minimize sand churn and maximize oil production.


  • Extended ESP run life from 72 to 797 days.
  • Increased the well’s production from 11,800 to 21,000 bbl/d [1,876 to 3,339 m3/d] —exceeding the well’s previous peak flow rate.
Products Used

Extremely Abrasive Colombia Well Produces for 797 Days with a Rugged Maximus ESP System

Engineered system with hardened stage metallurgy extends average run life from 72 to 797 days and enables doubled production, Colombia

Destroyed pumps and choked production

Production fluids with abrasive sand are a continuous challenge for artificial lift equipment because these fluids generate wear, reduce lifting efficiency, and increase the frequency of well interventions due to failures. High flow rates compound the problem by exacerbating the solids abrasion.

An operator in Colombia faced this scenario in the Llanos field, where solids-laden fluid production compromised ESPs and threatened field economics—not only from frequent interventions to replace ESPs but also from restricting production to avoid even worse damage.

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Left: After 797 days, the optimized stage remained in good condition despite high solids production. Right: After producing an offset well, a conventional stage was found to be plugged with solids.

One well, for example, typically produced 10 to 100 ppm of solids but peaked with 1,000 ppm of solids in 13,000 to 15,000 bbl/d [2,067 to 2,385 m3/d] of fluid. Two ESPs in the well failed with an average run life of only 72 days, although the well production had been choked back to approximately 75% of its potential (11,800 bbl/d [1,876 m3/d]) in an attempt to reduce the scouring. The operator asked for a more robust solution.

Rugged ESP system and engineered startup plan

Schlumberger engineers began with thorough root cause analysis of the failed ESPs, finding significant erosion of impeller and diffusers, erosion and abrasion of the radial bearing, and damage to the pump head radial support.

The next step was to design a new Maximus ESP system that could survive in the extremely abrasive downhole conditions. In particular, the engineering team selected

  • upgraded 5530 stage material for the impeller, diffusers, and housing
  • robust tungsten carbide bearings to improve lifetime
  • full bearing housing configuration for increased shaft stability
  • keyless bearing sleeves to eliminate a stress riser that led to cracking
  • shedder retainer to mitigate sand fallback and related damage to the head bearing.

Engineers also developed a plan to restart the well production slowly to minimize solids churn and then ramp up production slowly.

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Production was increased slowly to minimize solids production and the extreme abrasion experienced in prior operations. The result was longer run life and improved well productivity.

Maximum production and >2 years of run life

The new ESP was installed in the well in June 2012 with a production target of 14,000 bbl/d [2,226 m3/d], which was 6,000 bbl/d [954 m3/d] less than the production from the prior ESPs. In the first 3 months, solids production reached as high as 130 ppm. After 6 months, the solids production dropped, and the production target was increased. The slow improvement continued, and the well eventually reached 21,000 bbl/d [3,339 m3/d], exceeding prior peak flow rates from the well.

The ESP continued to produce the solids-laden well fluids for 797 days—11 times longer than the average run life of the prior two pumps—before being pulled out of the well because the electrical cable and motor fatigued after reaching their normal run life. The pump housing, impellers, and diffusers were found to be in good condition with no significant wear, demonstrating the success of the engineering design.

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The new, more robust pump base (left) survived in the abrasive conditions, as compared with the conventional pump base (right), which was severely damaged by abrasion in an offset well.
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