The goal is to optimize reservoir development through the acquisition of more accurate and timely information regarding the production performance of individual wells or individual completion intervals within a well, improving field development economics and increasing recovery.
?Intelligent wells? incorporate advanced completion technologies that provide downhole information that gives oil and gas producers increased control over fluid production. Reliable operation of the downhole components and the telemetry system for communicating with the surface are critical issues for successful application of this new technology. The objective of this project is to develop and demonstrate a new downhole fluid analyzer that will measure produced fluid fractions downhole in real time without interfering with production. The analyzer will use permanent remote sensors and fiber optic cable data transfer. This system is being developed as an alternative to conventional intelligent well monitoring systems that utilize downhole electronics and electric lines that run to the surface. This system?s sensor reliability is potentially much higher due to the lack of downhole electronics.
The device being developed under this project uses near-infrared spectroscopy and induced fluorescence measurement to accurately determine oil, water and gas concentrations over a broad range of water cuts. The principle of operation is based on the principle that light passing through a fluid will be absorbed at specific wavelengths depending on the chemical composition of the fluid. By analyzing this absorption, one can determine the chemical composition of the fluid and distinguish among oil, gas and water fractions.
The active components in this unique system are located at the surface while the only downhole components are optical windows located at the point where flow measurement is to be made, and a fiber optic cable connecting those windows to the surface system. Potential applications would be downhole monitoring of multiphase fluid production or downhole separation equipment. The system would be capable of monitoring multiple downhole probes, and has the capability for geographically remote control, monitoring, and data processing.
The project is divided into two phases. Phase I (now completed) included research, development, and laboratory testing of the new system. Phase II will demonstrate/field test a prototype (Petro-Max?) in a flow loop and in a flowline and well operated by a commercial partner.
Phase I work was modified twice to address changes in the sensing approach, ultimately settling on a new, near-infrared method. Testing showed that the sensors? output signals produced excellent correlations with the known percentages of oil, gas, and water, over a range of inclinations, flow rates and flow regimes, as well as over a range of pressures and temperatures.
The purpose of Phase II of the project is to make field ready and field test the PetroMax? fluid composition sensing technology developed under Phase I. The field testing phase includes three tasks: an environmental test of the optical fibers? performance at high temperatures and pressures, a demonstration of the performance of the complete system installed in a surface flow line on a producing well, and a full downhole installation.
APS Technology – Project management and all research products
Old Dominion University – laboratory testing
ChevronTexaco – Phase II field test partner
Cromwell, CT 06416
APS?s Downhole Fluid Analyzer technology provides the critical piece of the reservoir production puzzle in terms of enabling the determination of fluid fractions in combination with temperature, pressure and fluid flow, all without the use of active downhole components. The technology has potentially broad market appeal.
Permanent downhole sensors provide the operator with a better understanding of subsurface conditions. With a more complete understanding of dynamic downhole conditions, operators can manage the remote opening and closing of downhole valves or the down-hole processing of reservoir fluids. These sensors allow the operator to:
Current Status and Remaining Tasks:
APS Technology and ChevronTexaco have been unable to come to an agreement for the field testing of the tool. The two companies negotiated for 2 years with no signed agreement. Within the same period of time, no additional companies had approached APS to test the tool. The feeling is that because this tool is one that would be deployed for several years in a production well, companies were not willing to take the risk of putting it in their well without proven demonstrations. Therefore, both DOE and APS have decided to end the project at it?s current point, which is at the end of Phase 1. Phase 2, Field Demonstration, will not be performed.
Project Start: September 25, 1998
Project End: November, 30, 2006
DOE Contribution: $782,163
Performer Contribution: $366,177
NETL – Gary Covatch (firstname.lastname@example.org or 304-285-4589)
APS – William E. Turner (email@example.com or 860-613-4450)