Challenging oilfield economics are incentivizing producers to increase asset values by extending production in mature reservoirs, even reopening abandoned wells rather than launching new drilling campaigns. Artificial lift has a key role to play in this growing trend. The tried-and-true methods, including electric submersible pumps (ESPs) and rod pumps, continue to prove themselves as worthy workhorses in bringing old wells back to life.
Emerging with the growing trend is a strategy for selecting the most appropriate artificial lift method to reinvigorate a particular field or well. Rather than relying on guesswork, familiarity with a certain type of artificial lift or bias toward one method or another, reservoir and production engineers are recognizing the benefits of using quantifiable field data to measure a field’s economic and technical potential and develop a streamlined workflow for selecting a customized lift approach for the entire life cycle of the well.
Engineering an artificial lift strategy that balances economic factors with specific well application considerations can be a game changer for exploiting complex reservoirs where recoverable reserves remain by extending equipment runlife, reducing the cost per barrel of oil and boosting incremental production. A workflow designed to maximize artificial lift reliability and performance was implemented in a mature field in South America, for instance, as the centerpiece of a strategy for the reactivation of 10 abandoned wells.
Designed to simplify the process of selecting the artificial lift method that best suits operator objectives, the Schlumberger LiftSelect strategic production planning service uses available field and reservoir data to model well behavior. The service combines the vast amount of data from conventional manual workflows to streamline the decision-making process for selecting the optimum artificial lift method for a specific well.
An initial screening of the field narrows the options using software that evaluates the seven major types of artificial lift against well criteria. Those include well depth and deviation, downhole temperatures and pressures, produced fluids and solids, availability of power, and surface facilities and flow assurance issues such as paraffins and solids production.
The service also has the capability to calculate results as production rates, cumulative volumes, capex, opex, net present value and pump properties. Single artificial lift evaluation simulates well performance using one method for a given period and compares methods. Scheduled lift analysis helps optimize a schedule for transitioning between lift methods. Full lift optimization determines the most appropriate lift method for each phase of well life, including natural flow if applicable.
Reactivating 10 abandoned wells
Considerations for reopening abandoned wells include deep installations, low production rates and problems related to flow assurance, which often result in premature artificial lift equipment failures and repeated interventions that impact the field’s ability to produce from an economic standpoint. To develop a strategy for extending production in these wells, it is essential to understand the issues that led to the abandonment in the first place.
Discovered in 1970, a challenging mature field in South America provided a sample group of 10 abandoned wells with varying production characteristics and well profiles to introduce the workflow for artificial lift selection. None of the wells had the ability to flow naturally, yet if reactivated, the wells’ combined production potential could deliver at least 1,000 bbl/d to the overall field production.
Nine of the wells were drilled in the last decade, and one well was drilled in 1981. Because of the field infrastructure and design, all of the wells were initially completed with conventional ESPs for artificial lift, a method that offers wide flexibility and operating range over the life of the well.
However, changing reservoir conditions, rapid production declines in the first months after the wells were brought online, scale buildup around the equipment and design input uncertainties related to reservoir properties resulted in multiple pump failures traced to 58 events, according to a post-failure analysis (Figure 1). Most of the wells averaged two interventions per year to address low flow rates, solids, corrosion and scale. The reservoir also showed a lower productivity index than was initially anticipated, meaning the artificial lift equipment was oversized for the application. As a consequence of these factors, the wells were temporarily abandoned.