In the oil industry, any progress in technologies designed to enhance production is most commonly based on empirical discoveries and only later followed by attempts to develop a consistent physical theory to explain, analyze and predict field behavior. However, in 1997, a group of scientists and engineers sought to change that mindset. Through a series of laboratory tests using a rigorous theory, this group developed a new fluid flow enhancement process for oil recovery and groundwater remediation.

The process is modeled after the effects of earthquakes on the pores in rocks to stimulate the flow of oil. As early as the 1950s, earthquakes were observed to affect fluid levels in oil wells. Increases leading to enhanced flow were often reported. It was also observed that water/oil ratios changed during an earthquake swarm — sequences of nearby earthquakes striking in a short period of time with no single earthquake serving as the main shock. Wells with initially large water/oil ratios were observed to have lower post-earthquake swarm water/oil ratios and vice versa in wells with initially low water/oil ratios. As a rule, beneficial effects decreased over time following a seismic event.

Further research into the seismic wave theory was conducted by scientists at Wavefront. It was determined that, in addition to the conventional energy waves that were assumed to exist by traditional seismic theory, another type of wave was created as the seismic energy passed through and interacted with the solid/fluid matrix in the underground environment. Using this research, the scientists created a proprietary technology called Powerwave. This is an injection process wherein, with each impulse, a volume of liquid is introduced through a casing or tubing and is forced at high accelerations by downhole devices into the reservoir. The injected fluid then increases the porosity, pressure, permeability, saturation and homogenization of an ever-increasing coherent volume of the porous media through porosity dilation (expansion of the pore throat).

Theories, research and hypotheses are one thing; the question is, does it work? In short, yes. Since 1998 the system has been successfully applied in heavy and light oil, in high- and low-permeability reservoirs. Table 1 outlines the areas where the process has applicability to the oil industry.

The effects of the system on well stimulation with the use of chemicals (acid) can be defined by two separate coil tubing (CT) acid stimulations performed on a horizontal and vertical well, respectively.

Both wells were cased, cemented and perforated in the Monterey shale formation with a mixture of quartz and CT-phase porcelanite as well as having natural fractures and dolomitic episodes that posed potential problems to stimulation fluids. Each well was treated with 1 bbl/ft of 15% Fe pad acid followed by 135 gal/ft of 12% HCl/3% HF (mud) acid and displaced with 10 gal/ft of clay stabilizing fluid. The acid recipe and volumes were chosen for their past successes on the shale. Furthermore, both Fe and mud acids were “tagged” with 0.50 mCi/1,000 gal of Ir-192 L.D. Zero Wash (iridium) and 0.36 mCi/1,000 gal of Sc-46 L.D. Zero Wash (scandium) radioactive tracers, respectively, for the trial to determine if dispersion and deeper penetration were achieved. Tagging of the acid streams with iridium and scandium and investigating with the SpectraScan permitted conclusive statements about the diversion capability of the process to be drawn as detailed in Webb, E., Hassan, K., and Warren, J., 2006, “Case Histories of Successful Stimulation Fluid Dispersion Using Pressure Pulsation Technology,” Twelfth European Coiled Tubing and Well Intervention Roundtable, November 2006, Aberdeen, Scotland (Webb).

The SpectraScan log run after placing the stimulation fluid was used to determine if treatment was successful in dispersing the acid more uniformly throughout the well bore while also achieving deeper penetration. Figures 1 and 2 show the SpectraScan log for both wells placed next to openhole logs. In both presentations, the two wells indicate that both Fe acid and the mud acids were well dispersed throughout the well bore. The logs also indicate deeper fluid penetration over portions of the well bore.

Previous investigative work after stimulating by bull heading the acid (i.e., open-ended CT) indicated the majority of stimulation fluid affected a very short pay interval, typically where a fracture or dolomite episode occurred. Therefore, the treatment did demonstrate greater dispersion and deeper invasion versus standard injection practices, as described by Webb.
Perhaps the most significant utility of stimulation treatment is its impact on liquid injection (water, CO2, surfactant, etc.) during secondary and tertiary oil recovery. In many oil fields, waterflooding is initiated well before any significant depletion takes place in order to avoid gas coming out of solution anywhere in the reservoir and to maintain well productivity. However, there are instabilities associated with high-rate and high-pressure water injection. These advective instabilities are related to viscosity differences under a driving pressure and include fundamental viscous fingering (mobility ratio controlled), permeable streak enhancement through water flushing by the more mobile phase, coning and hydraulic fracturing.

For a production company the ability to inject larger volumes of water into a producing formation is an important operational objective as processing rate directly affects production revenue. Volumetrically, where input equals output, increasing input by a factor of two also increases output by a factor of two. If the proportion of water and oil of the output remains constant or tends toward more oil, the production company would recognize greater production revenue. If a formation is not volume-balanced with respect to injection/ production ratios and the reservoir is in a stage of “filling” the pore space to reestablish pressure drive, then the ability to increase injectivity beyond rates typically modeled and measured in the field would also be beneficial as a production company may realize improved production and the revenue associated with it sooner.

Recently, the system was put to use in a mature oil field lease operated by the service company in Rogers County, Okla.

Operations in the company’s lease commenced in 1902 and are within 100 miles (160 km) of Nellie Johnstone No. 1, Oklahoma’s first commercial oil well, completed in April 1897. Oil production from the leases is from the Bartlesville formation having an average permeability
of 19 mD at a depth of about 500 ft (152 m). Waterflooding has been sporadically applied through the injection of produced water. However, the low historical injection volumes have not allowed for pore space filling, and the reservoir has minimal pressure support as well as minimal reservoir pressure.

The primary focus of the organization’s Oklahoma operations is to validate the efficacy of the process; more specifically, how the stimulation treatment improves injectivity rates and
oil recovery rates for waterfloods in mature assets. In Rogers County five
of the downhole devices are deployed on tubing in water injectors at a depth of approximately 500 ft. The system has provided consistent results with respect to overall improvements in the rate of water injection versus standard injection practices at the same relative supply pressure. As shown in Figure 3, the twofold increase in injectivity rate has been independently verified by engineers with a major oil producer. Production increases using the company’s Dragonfly tools have been reported to average 199% over static injection results.

Closure
The process is well understood and is becoming widely known in the oil industry. Numerous field applications since 1998 have shown that it is more effective than traditional waterflooding or conventional well stimulations where liquids are injected. The beneficial effects of the process are chiefly related to the generation of long-wavelength displacement waves, which bring dynamic energy to the liquids at the pore scale. This helps them to overcome barriers to flow. The system could potentially change production approaches in heavy and light oil deposits.

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