Whenever a well no longer produces at the volume desired, artificial lift systems are considered. Some experts have indicated there are 31 attributes that can be considered with some more significant than others. Today, oil operators use a whole matrix of criteria and decision trees to predict what the wellbore will give up and what method to use.
Among the more significant determinants in pump selection are reservoir characteristics (temperature, pressure, optimal production rates, fluid properties, quantity and type of produced solids, free-gas production) and individual well conditions (well depth, inclination, completion design, surface facilities, energy source). Other considerations may include operational constraints such as horsepower, injection pressure, injection rate, system run life, repair and maintenance, energy costs, capital expenditure, and even geography.
The Decision Process
Selection of the proper artificial lift method is critical to the long-term profitability of most producing wells. A poor choice can substantially reduce production and increase operating costs. Prudent production engineering requires continuous review of the lift method’s performance, although once a method is chosen it normally stays in place.
How and when a lift system is used is normally an iterative process involving the customer and a representative of the pump company. One of the key indicators commonly used in decision-making is the PI/IPR curve. PI stands for Productivity Index (Producing rate/Static bottomhole pressure - flowing bottomhole pressure). This is the slope of a straight line that describes the ability of the well to produce and can be used only as long as the producing pressure is above bubble point pressure. IPR stands for Inflow Performance Relationship. This is a curve function that also describes the ability of the well to produce used whenever the producing pressure is below bubble point pressure. When the IPR curve proves the reservoir pressure is incapable of producing the available fluid to surface, then alternative producing methods are sought to provide an acceptable ROI for the producer and shareholders.
Sizing Up the System
When the amount of fluid to be lifted is determined and reservoir/well conditions understood, then the required form of artificial lift can be selected. At this point, the optimum size of the pump, set depth and parameters for other support equipment are chosen and designed if necessary.
Pumps tend to be sized according to the maximum expected fluid rates. Since this varies with the life of the well, some operators are moving toward technologies, which allow pump sizes to be easily changed. Today, many manufacturers use computer programs and an integrated system approach to find the most suitable solution for the application.
To assist rod pump selection, Lufkin has modern predictive computer programs that utilize sophisticated mathematical models. The company’s SROD program optimizes the entire pumping system to ensure the best possible performance under existing field operating conditions, including deviated and horizontal wellbores, or shallow, high volume applications.
In recommending ESP systems, Centrilift focuses on production optimization in total. According to Director, R&D/Systems Engineering John Bearden, “For years, our applications engineers have not only helped customers choose the right pump, but also optimize the best running points of the pump with variable speed drives that change flow rates and lift by changing speeds. Now we have a system to tie in software to monitor a wellbore 24/7. We can do as much as the operator allows. We can keep the system on line, change speeds, keep it optimized, identify detrimental running conditions or shut it down automatically before failure if it reaches a critical condition. What we’re trying to do is not only reduce their costs, but also keep the system on a peak performance point and stop it before a failure leads to expensive remedies. Also, we allow the operator to manage workovers better with a predictive look at run time and failure potentials. Our interest is to optimize the whole project and reduce operating expenses and downtime. It’s a proactive approach that saves time and money down the road.”
Cost/Features
Expenditures for pumps generally fall into the broader category of production costs (sometimes called lifting costs) including those incurred to operate and maintain wells and related equipment and facilities plus ancillary expenses. For older, watered out low volume wells, operators normally look for the minimum cost per barrel lifted including all support costs. For high volume wells customers tend to seek equipment with the best reliability and mean time between failures since the wells must pump continuously in high cost environments. No matter what the case, the lift method must be able to meet the pumping volumes the reservoir will deliver.
There are a host of desired features that may come into play when selecting a pump. Among these are Ruggedness/Forgiveness (You can “pump off” a beam pumped well and not suffer the same consequences as starving an ESP or PCP.), High Efficiency (low power cost), Automation, Diagnostics Capabilities, Product Service Support, Total Cost Of Installation and Operation and Ease of Use.
More and more, operators are turning towards technology recommendations from manufacturers and service companies to achieve objectives with optimized system designs.
