Frank Hartley • Houston
Interpret, optimize downhole treatments in real time
Schlumberger has developed a coiled-tubing application using real-time downhole measurements to interpret and optimize treatments while they are in progress.
The ACTive coiled-tubing application can function in various well configurations.
A ruggedized high-bandwidth fiber-optic cable deployed inside the coiled-tubing string connects bottomhole sensors with surface monitors and controls, allowing engineers to measure, interpret, and act on downhole events in real time.
“You can only improve what you can measure,” says Sherif Foda, vice president, coiled-tubing services, Schlumberger. “When you know exactly what’s happening downhole, you can adjust job parameters in real time based on downhole measurements. For the first time, operators can manage their treatment and make a difference to the results with complete confidence when it matters the most – while the operation is still in progress”.
New digital flow profiling system
Sensornet together with partner FloQuest says it has developed a real-time digital flow profiling (DFP) system that can increase production, reduce operating costs, and improve recovery. This system can locate accurately fluid entry points across an entire reservoir and identify fluids present, Sensornet says.
Wells expected to benefit from DFP include conventional and complex, multilaterals, intelligent oil or gas producer/injectors, long horizontal wells, and wells with infrequent or no production logging technology (PLT) deployment.
Sensornet has developed a real-time digital flow profiling (DFP) system which aims to increase production, reduce operating costs, and improve recovery.
The system provides continuous PLT-type data in highly deviated and complex wells without the costs, risks, or deferred production associated with conventional logging, according to Sensornet. As well as monitoring the flow distribution in production and injection wells in real time, the system also provides information often not accessible with traditional production logging. Traditional techniques often provide a snapshot of what is really happening in the well and are potentially more expensive to run, the company says.
Zonal flow allocation is determined using Sentinel distributed temperature sensing (DTS) technology. With a resolution of 0.01°C every 1 m along the wellbore, the Sentinel system is applicable in wells needing monitoring to identify thermal events. The ability to provide updates every 10 seconds also allows transient events to be analyzed, providing a new dimension in DTS interpretation.
The DFP system was recently deployed by a Middle East operator to understand flow distribution in a complex well. By monitoring the well using the Sentinel acquisition unit, accurate flow distribution was identified and delivered a system to achieve total coverage of the well with no further impact on installation and operation, Sensornet says. Within minutes of running the completion, the DFP solution provided real-time data gathering and interpretation, and complete temperature profiles were captured, validated, and delivered in real time.
Compared to the alternative of a horizontal well intervention on coiled tubing, $300,000 was saved at substantially lower risk, the company says.
Central to the DFP system are the interpretation capabilities provided by the FloQuest software, according to Sensornet. This data management and visualization front end enables rapid data analysis and processing. With comprehensive flow and thermal simulation engines, FloQuest enables the accurate inversion of DTS data to flow distributions, providing Virtual PLT information from temperature profiles.
“The correct analysis and interpretation of flow distribution and content in oil and gas wells can have a significant impact both financially and logistically on a well’s production life and, ultimately, the success of an operation,” says Neale Carter, Sensornet CEO.
New high-pressure packer cups hold 18,000 psi differential
Rubberatkins has developed the HP Cup, a new range of high-pressure packer cups that will hold differential pressures up to 18,000 psi at temperatures reaching 160º C (320º F). This is a reliable solution for liner hanger, well intervention, sand fracturing, sand control, and wellhead testing operations.
Its thin walls can accommodate larger outer diameter (OD) mandrels allowing increased flow through the mandrel inner diameter (ID). The HP cup has an integral cup and thimble, and its flexibility provides increased reliability when working at very high pressures and temperatures to minimize risk, according to Rubberatkins.
“The HP Cup is designed to maximize production while minimizing risk by securely sealing high pressures at temperature,” says Nick Atkins, director of Rubberatkins. “We designed the HP Cup in a range of sizes which fit three custom designed mandrels. Cups can be tailored to suit the individual needs of the client and any casing size and weight and mandrel OD. Every job has different issues and problems and therefore different needs. Each requires its own distinct solution. To meet these requirements, we can adapt the rubber compounds in our products in accordance with individual environmental parameters.”
Reservoir monitoring to increase recovery
StatoilHydro will use Weatherford’s reservoir monitoring systems over the next eight years to help increase recoveries from existing and new wells. This technology includes downhole optical monitoring equipment, including pressure and temperature sensing systems and downhole multiphase flow measurement, for both platform and subsea wells.
Optical sensing systems can have advantages in long-term monitoring, particularly in hostile environments including high temperature and pressure, high shock, and vibration, according to Weatherford. Unique combinations of both existing and new optical sensors under development open possibilities for enhanced data collection and resource management.
