Using powerful new measurements technology and systematic analysis to solve old problems can have long term benefits.

Of the approximately 885,000 wells flowing liquids worldwide, only about 55,000, or 6%, flow naturally. All others require some type of artificial lift. These include approximately 115,000 Electrical Submersible Pumps (ESP), 66,000 gas lift, 60,000 Progressing Cavity Pumps (PCP), and 591,000 rod pumps. It is estimated that two of three artificially lifted wells could be candidates for significantly improved operation and increased production. Even with artificial lift, regularly monitoring the lift system and completion to ensure it is operating at its optimal efficiency is imperative for maximum production and drainage of the reservoir.

A new artificial lift optimization service called PowerLift from Schlumberger enables a fast and clear view of the artificial lift system's performance. It identifies under performing artificial lift wells (well candidate identification) and uses the appropriate technology to identify the reason the well is under performing (analysis). The service provides recommendations and actions to optimize production (execution) and follows up with validation of results (evaluation). The process focuses on the lift system and wellbore performance only.

For ESP and PCP wells, the minimum surface measurements include tubing pressure and temperatures and casing pressure. Minimum downhole measurements include pump intake and discharge pressure, intake temperature and motor temperature. Using permanent downhole monitoring technology allows the thorough diagnosis of the wellbore pressure response due to the effects of the lifting system.
For a gas lift system, minimum measurements include tubing pressure and temperatures, injection pressure and temperatures, injection rate and multiphase flow data. Periodic surveys of pressure, temperature and flow can be obtained from permanent gauges or gauges installed temporarily via wireline, and a multiphase flowmeter.

The PhaseTester VX mobile multiphase well testing unit is designed for easy deployment. This technology provides the ability to measure flow accurately, consistently and with fast response time, and is a key to performing multi-rate tests on gas lifted wells or diagnosing well instability. The unit can be installed to accept fluids from the flow line and then return them after measurement. Pressure loss across the system with the multiphase flowmeter is typically 3-30 psi, significantly lower than with conventional test separation systems. Portability, fast response time and good metrology make this a key system enabler.

espWatcher monitoring system for electric submersible pumps

espWatcher is a service specific to ESPs that acts as a technology enabler to increase the program's efficiency. It allows a user to increase production and reduce spending by avoiding unnecessary, costly pump replacements and system downtime by optimizing the pump's operation and reducing or eliminating trips to the field to resolve any problems. For under-performing wells, espWatcher is able to identify and allow prioritization for production improving interventions.

The new monitoring system for electric submersible pumps features remote, satellite-based data acquisition, immediate alarm and alert call out notification, remote pump startup and speed control, and remote resolution of pump problems. It is enabled by real-time monitoring and data delivery, which provides reliable and secure remote connectivity and viewing of the ESP variable speed drive controllers monitored by artificial lift monitoring systems.

The espWatcher system receives real-time streaming data from the wellsite to the remote location where the well and pump are continuously monitored and surveyed. In "interactive mode," the monitoring system will automatically alert the user when a well requires analysis and diagnosis as a result of changing operational conditions. Real time monitoring and surveyed data is the enabler for improved well candidate selection, allowing for more efficient scheduling of the PowerLift service, The service uses data sent to espWatcher and performs an analysis and diagnosis of the well and pump operations.

Results

Fine tuning the candidate well's operation to increase net oil production by 10% is the baseline performance of PowerLift. Gains in the area of US $23,000 per day have been experienced, and on some individual wells, gains in production rates of nearly 200% have been achieved.

Several examples of field successes include a Middle East operator that experienced an 88% gain in oil production from 30 wells, and in Latin America, a heavy oil gas lifted well posted a 15% increase in production coupled with a 6% decrease in the gas injection rate. In this last example it was determined by the gas lift performance curve that the optimum injection rate was not being utilized. It was recommended that the gas injection rate be reduced to optimize production.

In the Far East, an operator achieved an oil production increase of 1,159 b/d from 16 land wells. In one field oil production rose 220%, or 414 b/d, while oil production in a second field increased 33%, or 745 b/d. The total increase of 1,159 b/d translates into a 47% increase in daily production. Based upon the operator's economic hurdle for oil prices of $20 per bbl, the result is more than a $23,000 increase in daily revenue. The results were based on well tests and flowing gradient surveys before and at least two days after changing to casing operated valves and orifice valves.

Colombian operator, Hocol, S.A., selected the espWatcher service to provide remote monitoring and control of ESPs. The first phase of implementation involves connecting approximately 70 remote ESP variable speed drives in more than 20 geographic locations.

The service was already proven in two field trials operated by Hocol that demonstrated reduced costs associated with field monitoring and management. The system also increased safety by reducing the exposure of operating personnel to remote field risks. The field trials demonstrated the ability to extend ESP run life through continuous remote pump monitoring and immediate proactive notifications of changes in the pump's normal operating parameters.

Case Study

Initial Field Trial. The PowerLift field trial was performed in Venezuela and incorporated PhaseTester Vx multiphase flowmeter, slickline services and gas lift services. The intention of the field trial was to identify lift system improvement candidates from four preliminary candidate wells.

The levels of testing were broken into four categories:

• Level 1 Singe Rate Test (SRT)
• Level 2 Multi Rate Test (MRT)
• Level 3a MRT with Flowing
Gradient Survey (FGS) and
Pressure Build Up (PBU)
• Level 3b NOVA valve installation and then MRT, FGS and PBU

The four preliminary candidates received Level 3 testing. The information was then analyzed and a recommendation made to install the Nova gas lift orifice valve in one of the wells. The same well was retested again, but at a later time in the Lasmo Dacion field operations schedule.
An additional Level 3b candidate well was identified and would also have the NOVA valve installed later in the field operation schedule.

The two remaining NOVA candidates were identified as needing intervention for the installation of standard gas lift technology.

In all, 18 wells were tested using PowerLift and the multiphase flow meter. While several wells did not post increased production rates, other wells recorded percentage gains in production ranging to nearly 22%, with most experiencing gains above 6%.

Egyptian land well. A well in the Balayim field operated by Petrobel in Egypt showed more than a 50% increase in production following diagnosis with PowerLift and the use of downhole monitoring. Before the optimization process, the well was producing 236 b/d of oil with ESP. Following the process and the recommendations, oil production rose to 487 b/d, a 51% increase.

Data from the downhole multisensor and surface multiphase metering indicated the ESP was being started without equalization of pressure between intake and discharge. Starting the ESP with this differential pressure can increase the possibility of breaking a shaft.

Combining PhaseTester Vx information with intake and discharge pressures provided accurate validation of flow rate and fluid properties. The pump was diagnosed with a broken shaft. Further analysis showed the pump was not drawing down the well to full capacity.

The decision was made to stop the well and replace the ESP with a larger one to increase production. The multisensor was installed in another well producing from a different reservoir for further field optimization. The diagnosis of the data was used to upgrade more than five wells producing from the same reservoir.