August 1998 Vol. 219 No. 8  Production

J. John Grow,  Engineering Editor

Cost-effective EOR technology

The U.S. has enormous oil resources. Right now, more than 135 years after the U.S. oil industry's birth, there is twice as much oil remaining in its reservoirs as has been produced, and for every barrel of oil produced, two barrels are left behind. The U.S. has about 350 billion bbl of oil remaining in place and most oil remaining in place, is hard to lift because it is locked in complex geologic structures and bypassed by conventional technologies, or simply beyond today's production capabilities.

As part of its continuing effort to develop advanced technologies for crude oil recovery beyond conventional methods, DOE is trying to develop better, more economical ways to flood an oil-bearing formation with gas, chemicals or microbes. The following groups have been selected to conduct EOR research in these areas:

• The University of Utah is looking at how Chevron can prevent the chemical properties of oil in its Colorado Rangely field from breaking down during CO₂ flooding, yielding a sticky, asphalt-like substance.
• University of Pittsburgh will focus on improving gas-flooding control by increasing CO₂'s viscosity, or flow resistance, to a level comparable to the oil being displaced.
• New Mexico Institute of Mining and Technology will look at optimizing chemical gel control in fractured reservoirs to reduce salt-water production during oil field operations.
• The University of Southern Mississippi is trying to develop a new class of smart copolymers, natural or synthetic, for fluid movement control during chemical flooding.
• Columbia University will design methods to reduce the surfactants' tendency to cling to reservoir rocks while surfactant flooding.
• University of Oklahoma, Norman, is to develop microbial strains that can consistently produce high levels of biosurfactants under simulated reservoir conditions, and which can be used under a wide range of conditions.
• BDM Petroleum Technologies is researching a combined microbial-surfactant, polymer-surfactant system.
• The University of Texas at Austin is trying to extend capability of an existing mainframe or supercomputer simulator for modeling advanced oil recovery methods.

Each project will last 36 months; total cost is $7,433,912. Researchers provide 23%, and DOE carries the remaining 77%. Project management is by the National Petroleum Technology Office in Tulsa, Oklahoma.

EOR increases recoverable crude to more than 432 million bbl. Pt. McIntyre field is approved for a $44-million EOR project to increase crude output by more than 32 million bbl, or 5,000 bopd, by 2006.

Pt. McIntyre, the third-largest producing field in the U.S., averages roughly 140,000 bopd. ARCO owns a 30% field interest, Exxon a 38% stake and BP the remaining 32%. Startup of the EOR system is expected in late 1999. The project will require fabrication of two truck-able modules, construction of a 12-mi pipeline and North Slope installation work.

Unlike its predecessors at Prudhoe Bay and other North Slope oil fields, the Pt. McIntyre EOR system will use high-speed, oil-free, intelligent motor compressors to supply miscible injectant — a gas and water mixture — at the field's two drill sites. The new compressors reduce module size by more than two-thirds, 150 sq ft vs. 600 sq ft, weighting out at 27 t vs. 90 t. Reduced size / weight enables truck, rather than barge, transport to the Slope, thereby generating a significant cost savings.

A Multiphase pumping system. Future operations may be simplified by transporting oil, gas and water mixtures in one pipeline, eliminating on-site separators and increasing production by lowering well backpressure.

Production is enhanced from wells normally limited by first stage separator pressure, and economical development of satellite fields will be allowed at greater distances from a central processing facility. Also, a multiphase facility costs about 70% of conventional equipment. However, multiphase pumps are less efficient than conventional facilities (30 to 50% efficiency vs. 60 to 70% for conventional systems).

Pump sizing for suction conditions is important when selecting a multiphase system. Oil, gas and water rates of the well streams that require pressure boosting must be determined. Additionally, gas / liquid ratios, suction pressure, required pressure rise, slugging tendency, solids concentration and estimated flow variations over the field's life must be determined.

Four standard multiphase pump systems with capacities ranging from 2,000 to 80,000 bpd of fluids are available through Flowtronex International. Each system is complete with a Leistritz screw pump, a motor, basic controls, instrumentation and piping needed for flows ranging from all liquid to gas slugs. The pumping systems have been installed in areas ranging from South American jungles to Middle Eastern deserts to the Alaskan North Slope.

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company