Even the most mature technologies are benefiting from the increased emphasis on production optimization. Companies that were satisfied to maintain the status quo at US $17/bbl to $20/bbl, or at $2/Mcf, are now seeing their way clear to invest in new ways to boost hydrocarbon production, reduce the amount of produced water, or both.
At the same time, companies are switching to asset management programs that require consideration of the entire producing asset from the pore to the stock tank. Often this management technique requires an efficient data gathering system to feed dynamic reservoir and production system models in real- or near-real time. Installing a system of production monitors requires telemetry to provide connectivity of all nodes to a central control point. And once asset connectivity is in place, it makes sense to consider production automation and remote control equipment. Automation allows near real-time response so operators can maintain production at or near optimum levels.
Field automation allows many traditional operations to be performed automatically by a single, multifunction wellhead controller. These operations can be triggered on command from the field operations center or made fully automatic, meaning they are implemented when a certain set of predetermined conditions are reached. Some of these activities include:
Intermittent well operation;
Plunger and gas lift operations;
Dewatering;
Compressor control;
Automated soaping;
Chemical injection;
Flow measurement;
Flow rate control;
Remote access; and
Data logging.
To be able to operate all these functionalities requires a versatile, reliable wellhead production controller. It must be adaptable to legacy systems so it can be applied to any wellhead with minimum modifications. For example, it must be compatible with existing electrical, hydraulic or pneumatic production equipment or subassemblies. And it must be easy to use and contain redundancies that keep it operating through temporary power interruptions.
Ability to adapt to changing requirements is a must. No one wants a controller that must be replaced or extensively modified each time another piece of wellhead or downhole equipment is added. Accordingly, leading suppliers are building controllers that can be software-customized, quickly and easily reconfigured by adding a plug-in chip or by a software update that can be Web-enabled.
While automation can ensure efficient 24/7 hands-off operation, a good controller must have clear, easy-to-operate manual controls and a visual display so field technicians can perform occasional on-site testing, diagnostics, repairs or intervention. Safety interlocks should ensure that no damage to the controller or its associated equipment or injury to the technician can occur when the module is opened for maintenance or inspection.
For a few years, many high-rate or critical wells have been equipped with surface and downhole production monitors and controls. Some so-called intelligent well systems (IWS) include downhole flow control so production can be optimized at the sandface. As long as 30 years ago, remote wells located in places like the Sahara Desert were equipped with monitoring and solar-powered satellite telemetry that allowed operators or service technicians to dial in to any well on the system from anywhere in the world. These were sophisticated and expensive. But now that the technique of real-time operation and control has been accepted as a good way to optimize production
economics, it makes sense to take the idea wherever it can go to boost asset profitability. Like most technologies, increased usage has resulted in design, manufacturing and distribution innovations that have greatly reduced the cost
of such systems.
A case in point
The Barnett Shale is a large, prolific formation located in Texas' Fort Worth Basin. Since its discovery, economics have been tight, and producers have had to be extremely innovative to optimize production by making reasonable and supportable investments. Recently, an operator there used an innovative application of mature production technology to double his gas production while maintaining the same level of oil production.
The technique used involved plunger-lift technology. Plunger lift utilizes the well's own gas production to facilitate lifting fluids to surface. As can be imagined, a well must have a certain minimum amount of gas flow to make the plunger-lift technique work at all, much less work economically. The operator had a 10,000-ft (3,050-m) well with 27¼8-in. production tubing. He wanted to determine if the well was a candidate for plunger lift because the technique can be extremely economical when applied in the right situations. Estimations determined that using conventional plunger lift, 4 bbl of fluid could be produced from the well each cycle. A "cycle" is defined as a reasonable time-frame to trip the plunger to surface and varies with well depth, pressure and flow rate. A good rule of thumb is Reasonable Time = Well Depth/500 fpm plunger velocity. Obviously, the more cycles one can make in a day the more fluid can be produced, but there is a limit. In this particular area of the Barnett, calculations based on conventional wisdom indicated that a minimum of 16 Mcfg/cycle production was required to operate the system. This effectively eliminates all candidate wells with less than 16 Mcfg/cycle production.
The operator called on International Lift Systems (ILS) who were able to introduce a solution that dramatically lowered the per-cycle gas requirement, allowing production of wells that were not previously considered as plunger lift candidates. ILS introduced staged plunger lift technology that uses some of the principles of the field-proved rod pump. By setting a plunger lift stage assembly in tubing at 6,892-ft (2,102-m), containing a ball and seat check valve, the company was able to shorten the plunger lifting cycle as well as reduce the fall-back time. Although they lifted smaller fluid volumes per cycle, they were able to increase the number of cycles while reducing the amount of gas required to power each cycle to 6.4 mcf/cycle. This essentially allowed them to maintain optimum oil production rate. At the same time, they made more time available for gas sales by limiting the minimum plunger fall-back time. The results speak for themselves (Table 1).
A software program developed by ILS enables the company to determine the best depth to set the plunger stage for each application to achieve optimum results. ILS staged plunger lift technology can be used with any plunger design. Using staged plunger lift technology, the company has dramatically increased the number of wells that are candidates for this application, and that can benefit from an extremely economical and reliable production technique.
The task of candidate selection can be daunting. When producing wells are equipped with intelligent wellhead controllers and appropriate communications, the entire field can be monitored and candidate wells identified in time to avoid production fall-off. The ILS wellhead production controller can be linked to the field operations center by the company's LinkMate Net web service, a secure multi-user web application that provides 24/7 access to remote well data using the Internet.

Comments