Carbon dioxide flooding is well accepted where supply exists and there is recognition of anthropogenic CO2 opportunities. There has not been a rush of mature field operators to the other enhanced oil recovery processes, though. Is this because of a lack of knowledge, confidence, human resources or capital? The Energy Forum addressed “knowledge” and “confidence” issues by helping participants understand where different EOR processes fit.

Ernie Majer with Lawrence Berkeley National Laboratory noted that mechanistic understanding of seismic stimulation was still evolving, but part of it involved relative porosity change. Lab results indicate the maximal relative porosity increase can be achieved by pulsing in the 30-140 hertz frequency range. Field results, which are in synch with theoretical considerations, confirm more favorable results in hard rocks, either carbonates or sandstones. Little stimulation was seen in “lossy” or soft rocks.

Wavefront’s Powerwave^TM tool creates an oriented pressure pulse, optimized by laboratory testing for a given formation. The process only works in consolidated sandstones. The pulsing distributes injected fluids more uniformly and typically increases injectivity four-six times. It can be used for well stimulation, in conjunction with acid or chemical treatments, or in waterflood projects.

There have been 175 single-well stimulations performed worldwide. Beneficial production effects from a couple days pulsing can occur for two-three months. One active field waterflood is Wavefront’s project in the Bartlesville Sandstone in Northeast Oklahoma. Wavefront’s business model is to participate, not provide the service as a vendor.

Louisiana State University researcher Dandina Rao has developed a “gas-assisted gravity drainage” process that has been licensed by Nelson O&G of Alabama. Gas (CO2, flue gas, etc.) is injected at the top of the formation through vertical wells, and production occurs through a horizontal well bore placed low in the formation. Injected gas spreads across the top, displacing oil downward. Good vertical communication is a must. Since the process doesn’t strive for miscibility, pressures can be lower, which lowers compression costs.

Since WAG injection is never used, reserves can be produced at low water cut. Fractures actually favor the process, acting like exchange conduits for oil/gas counterflow. Significant oil recovery continues after gas breakthrough. Nelson’s first field project is in a depleted sandstone waterflood. Modeling results indicate ultimate recovery could be increased from 26 percent of the original oil in place after waterflood to about 65 percent of OOIP.

Chemical costs were high and processes complex for chemical floods studied during the 1970s and ’80s. Paul Berger with Oil-Chem Technologies Inc. described the evolution toward lower chemical usage (up to 10 times less) to achieve mobilization rather than solubilization. In this mode chemical costs are $0.50-$5.00 per incremental barrel of oil, as opposed to the $8.00-$15.00 per incremental barrel previously.

Alkaline surfactant polymer (ASP) field projects (1986-2002 time frame) have yielded recovery in the 20-30 percent OOIP range. Typical ASP concentrations (by weight) are 0.1-0.3 per-cent surfactant, 0.6-1.4 percent alkali, and 0.1 percent polymer. Lowering alkaline concentration even further (0.1-0.6 percent by weight) can reduce absorption and operational problems.

Berger also described new work where surfactant is injected using pulsing techniques–an even lower cost process. Research by Rao at LSU is looking at surfactant-induced wettability alteration as opposed to reducing interfacial tension. Core floods show recoveries up to 94 percent using simple, inexpensive surfactants.

For some, microbial EOR means “introducing” microbes to the reservoir. Titan Oil Recovery Inc. takes another approach: identifying and stimulating/managing beneficial indigenous microbes. Nutrients are reservoir specific. As the microbes mature, they become hydrophobic, attaching to trapped oil and breaking it apart so it can flow. An emulsion that forms aids sweep. Results from several sandstone field projects (although the process also can work in carbonates) indicate incremental costs of $3.00-$6.00 per incremental barrel. Ideal screening criteria include 25-degree API gravity or higher, temperature below 176 degrees F, and salinity less than 7.5 percent (preferably below 5.0 percent).

Bob Westermark described Grand Directions LLC’s approach. It begins with assessing how much oil really remains. If the target is large enough–and it doesn’t have to be as large with the lowcost horizontal drilling approach that Grand Directions has evolved–more thorough geological and engineering analysis helps define where the bypassed/undrained oil should be.

Grand Directions can place open-hole laterals up to 1,000 feet long in competent rock for a fraction of the cost of conventional horizontals. With its low-cost drilling approach, if the lateral doesn’t find the expected oil, the company can plug back and redrill for minimal cost. Grand Directions continues to use the approach in its leases and will partner with other operators, drilling the laterals to earn an interest.

Beyond increasing participants’ knowledge and confidence, the forum stimulated “possibility thinking.” What if I combined my technology with that technology? Has your thinking been stimulated?