This paper describes the implementation of a methodology for classification of artificial lift system failures and adding a commonly used root cause failure classification from C-Fer (RIFT). The subject field is the oldest Colombian oilfield, which was discovered in 1918, and was produced by primary recovery, then by gas injection as secondary recovery; in the 80's the water flooding project started and finally, in 2006 optimization of water flooding took place increasing production from 4,500 bopd up to 40,000 bopd. Conditions are challenging for all types of artificial lift systems, including sand production, CO2 corrosion, H2S presence, high water cuts and unstable injection conditions. This methodology was applied to different artificial lift systems, such as: Beam Pump (BP), Progressive Cavity Pumps (PCP), Electrical Submersible Pumping Systems (ESP) and Electrical Submersible Progressive Cavity Pumping Systems (ESPCP). The starting point was the definition or limitation of the boundaries of every system, since some of them use rods for power transmission and others use a power cable. Then, every job in the well was defined as Failure, Failure No-ALS or No Failure in order to classify and look for ways to improve run life and decrease failures by implementing action plans with operations, engineering, and suppliers among others. The addition of root cause failure classification helped to refine the action plans in order to solve the issues. In some cases, it was necessary to customize RIFT classification in order to track local issues; such as: unstable injection wells, drilling operations in the same well location, etc (some examples are included). Included in this methodology, some KPIs: failure index, indirect failure index, pulling index, recurrence index, average run life, average run time were used. These KPIs helped track performance improvement in the last two years, getting excellent results.
The Cira Infantas Field is located in the Middle Magdalena Valley Basin. It was discovered in 1918, the first oil producing field in Colombia, reaching a peak production of 53,000 BOPD in 1939. The field has been subject to different methods of secondary recovery, gas injection and waterflooding since then. In 2006, a waterflooding redevelopment with injection-production system optimization was started. In the first year, oil production increased from 4,500 BOPD to 9,800 BOPD and injection increased from 12,000 BWIPD to 36,000 BWIPD. After an increase of the Failure Index in 2012, the artificial lift team developed a strategy to reduce this performance indicator based on process improvements including supply chain, design, storage, installation procedures, well start up and well surveillance. As of December 2014, the field has 1000 producing wells and 408 injectors. The most common artificial lift system (ALS) is Beam Pump (BP) with 760 wells; followed by Progressive Cavity Pump (PCP) with 135 wells; Electrical Submersible Pump (ESP) with 99 wells and Electrical Submersible Progressive Cavity Pump (ESPCP) with 6 wells. The main failure causes are associated with sand, corrosion (CO2 is present), poor monitoring and operation procedures among others. The application of the Root Cause Failure Analysis, RCFA was the first step to identify the artificial lift problems to be solved. One of the first conclusions showed the necessity to redefine the production range for the different ALS. This is an example that the problems are not always associated to the reservoir fluids, leading the team to define a strategy that covers all stages where ALS's are involved. The new implemented strategy yield a reduction in the ALS failure index from 0.67 to 0.47 in just 24 months. The savings enabled the operation to carry out additional well work (Workover & Well service) without additional funding.
Historically, electric-submersible pumps (ESP) were designed for a production above 3,000 BFPD. For lower flow rates it was necessary to install another artifical lift method such as beam pump (BP). In the Caño Limón and La Cira-Infantas fields, located in Colombia with 30 and 98 years of production respectively, the number of wells with flow rates lower than 1,000 BFPD has been increasing as well as the number of wells with BP as a lift system. The increase of failures in BP systems, and the greater cost of the completions compared to ESP, made it necessary for the analysis of other artificial lift methods to handle the required flow rates. Therefore, in 2013, the implementation of ESP technologies with a nominal flowrate of 1,000 BFPD were carried out without failures associated with the ESP system, showing that they were able to work under such conditions, reaching rates between 50 and 1,000 BFPD, thus becoming an effective option to replace the wells with BP, as long as the conditions of pressure and submersion allowed it. In La Cira Infantas field, 60 wells with rod faults of the BP system have been successfully replaced by ESP systems with flow rates ranging from 400 to 2,000 BFPD. This work explores the possibility of installing ESP technology in wells where it was not previously seen as an option, presenting the results of the implementation of this technology producing even lower flow rates than those in the initial sizing, reducing the number of failures and the costs associated with the continuous interventions of the Mechanical Pumping systems.
Electrical failures of the Electric Submersible Pumping ESP systems reached a record high in various Northern fields in 2014. A study was undertaken to identify and understand these failures and their root causes. The analysis revealed that the main cause of the system failure was either the power cable or the motor lead extension (MLE). Through continued developments in technology, the components of the ESPs have been upgraded to increase their performance, efficiency, and run life. In Llanos Norte operation, located in east Colombia, an increase in power cable failures was observed between 2012 and 2014. Those failures represented 50% of the total failures associated with downhole equipment with an average run life of 300 days and the main cause was mechanical damage to the cable sustained during installation. After a detailed well-to-well analysis to identify fault patterns, different reasons arose such as well tortuosity, high run-in-hole speed, changes in cable specifications and deformations caused by the accessories used to protect the cable. All of these items resulted in mechanical damage to the outer armor of the cable, exposing the insulation system to well fluid, which caused an increase in infant (less than 30 days of operation) and premature (less than 365 days of operation) failures. As an immediate action plan, a decision tree was created to determine run-in-hole speed according to different factors such as: well deviation, outside diameter of equipment and the internal diameter of casing; supporting the analysis with calculations of torque and drag. There were also additional actions implemented to reduce cable failures such as: changes in cable specifications (thicker armor and geometry), training the personnel involved in ESP installation (rig and ESP vendor), changes in the tools used for cable handling, use of new accessories for cable protection and upgrading power cables with lead jackets for applications in gassy wells. This paper presents a summary of the different solutions implemented after a thorough analysis carried out with an interdisciplinary team composed by personnel of the Field Operator and ESP vendors. The implementations of all actions represented almost MMUSD$ 4 in savings in three years over a population of 395 wells.
Production fluids with abrasive sand are a continuous challenge for artificial lift equipment (e.g. electric submersible pumps or ESPs) because these fluids generate wear, reduce lifting efficiency and increase the frequency of well interventions due to failures. This study summarizes the first implementation of hardened ESP stages in the Northern Llanos Field. The impellers used in the ESP system are made of a special alloy called Ni-resist Type 4. This alloy improves the resistance to erosion and abrasion over a traditional pump stage made of Ni-resist Type 1. A candidate well with high flow rate 20,000 bbl/d (600 bbl/d of oil) was selected for a field trial with these special pump stages. The prior ESP's failed with an average run life of 72 days even though the flow rate was restricted producing approximately 75% of its real potential due to the high amount of sand produced. This well is completed in a formation that produces high solids between 50 and 1,000 ppm. During the field trial of hardened stages, the candidate well reached a run life of 797 days, equivalent to 11 times the average of its previous ESP's with standard metallurgy. It also produced 20% above its fluid potential estimated by reservoir engineering and surveillance teams, and the frequency of well interventions was reduced. The paper shows a real case study that demonstrates production and run life increases as well as the capability of being replicated in other wells with high sand production.
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