Enhanced Oil Recovery Experiments Research Articles

Synergistic enhancement of oil recovery: Integrating anionic-nonionic surfactant mixtures, SiO2 nanoparticles, and polymer solutions for optimized crude oil extraction

Enhanced oil recovery (EOR) methods are essential for optimizing oil extraction from modern reservoirs. This research delved into the synergistic impact of combining anionic and nonionic surfactant mixtures with silica (SiO2) nanoparticles (NPs) in sodium chloride (NaCl) solutions, alongside the added enhancement of polymers, to improve crude oil recovery. The study comprehensively evaluated stability, rheological characteristics, interfacial tension (IFT) behavior, wettability alterations, and EOR experiments using mixtures of sodium dodecyl sulfate (SDS) and triton X-100 (TX-100) surfactants. Scenarios both with and without SiO2 NPs in a base solution containing 3000 ppm NaCl and 2000 ppm xanthan gum (XG) polymer were examined. Core flooding tests were carried out on San-Saba sandstone core specimens with low permeability. The stability tests and dynamic light scattering (DLS) analysis were performed to assess the stability of NPs in low saline-surfactant-polymer solution. It was observed that NPs significantly reduced the IFT between the test solutions and crude oil, with nanofluids exhibiting satisfactory stability at a 0.4 wt% SiO2 NPs concentration. Core flooding studies demonstrated a synergistic interaction between NPs and the binary surfactant-polymer mixture, resulting in substantially greater incremental recovery of oil in comparison with the case of using binary surfactant-polymer combination alone. The mechanisms contributing to EOR with nanofluids, such as IFT reduction and wettability alteration, were explored. Incorporating NPs at concentrations of 0.1, 0.2, and 0.4 wt% led to incremental oil recoveries of 4.01 %, 12.35 %, and 12.73 % of the original oil in place (OOIP), respectively, as opposed to the recovery achieved using only SDS + TX-100 + XG. Consequently, these findings advance the understanding of the potential application of SiO2 NPs in combination with the binary surfactant-polymer mixture as effective chemical EOR agents. Additionally, these insights aid in identifying suitable sandstone reservoirs for nanofluid application, contributing to the optimization of oil recovery strategies.

Residual oil start-up mechanism of polymer/surface dual flooding after polymer flooding in medium-high permeability reservoir

The remaining oil distribution and displacement mechanism of poly/surface dual flooding stage in medium and high permeability reservoir are not clear. In this paper, the reservoir conditions in Gangxi Area 3 of Dagang Oilfield were taken as the research object. Based on nuclear magnetic resonance and large model physical simulation experiment, the characterization of micro and macro residual oil start-up mechanism and enhanced oil recovery experiment were carried out respectively after polymer flooding poly/surface binary flooding. The experimental results suggest that polymer-surfactant flooding could increase the oil displacement efficiency by 12-29% after polymer flooding, and the contribution of porous to recovery degree is in the order of medium pore, large pore, and small pore. When the surfactant concentration is higher than 0.25%, the increase of oil displacement efficiency tends to be stable, and further enhancing oil recovery requires the expansion of sweep volume. Physical model experiments results show that medium permeability layer has the highest contribution to the recovery degree in the chemical flooding stage, and the displacement mechanism is mainly based on the synergistic effect of expanding sweep volume and improving displacement efficiency. The contribution of low permeability layer to recovery degree is next, and the displacement mechanism is mainly to expand sweep volume. The high permeability layer has the lowest contribution to the recovery degree, and the oil displacement mechanism is mainly to improve the oil displacement efficiency.

Experimental Study of CO 2 Responsive Enhanced Foam System

The channeling of CO2 seriously affects the development effect of CO2 flooding technology. In response to this problem, the construction of the CO2 responsive enhanced foam system and the evaluation of its channeling performance have been carried out. The foaming agent is optimized by the stirring method, the CO2 responsive enhanced foam system is constructed based on the optimization of foam agent, and the rheological performance test and the enhanced oil recovery experiment are carried out to study the stability mechanism and channeling plugging performance of the responsive enhanced foam system. The developed responsive enhanced foam system formula is 0.1 wt% AOS foaming agent + 4 wt% small molecule amine. The viscosity of this system is close to that of water before exposure to CO2, and the viscosity can increase by more than 18 times corresponding to CO2. The CO2 responsive enhanced foam system has obvious shear thinning characteristics, and its rheological equation conforms to the power law fluid rheological model. The enhanced foam system has stronger viscoelasticity than conventional foams. The foam comprehensive value of the enhanced foam system can reach more than 11 times that of the conventional foam system, which can effectively inhibit the CO2 channeling of heterogeneous low permeability reservoirs and improve the development effect of CO2 flooding in low permeability reservoirs.

Visualization of Spreading and Non-Spreading Oil Films in Gas- Assisted Gravity Drainage (GAGD) Process Using Novel NOA81 Microfluidic Platform

The presence of oil films in three phase flow of oil, water and gas through reservoir rocks has a significant effect on the recovery efficiency associated with various Enhanced Oil Recovery (EOR) processes like Water Alternating Gas (WAG) and Gas-Assisted Graviry Drainage (GAGD). Visualization of these oil films helps in having a better understanding of the conditions required for the formation of such films in a rock pore network. In this work, we have used a microfluidic platform consisting of Norland Optic Adhesives-81(NOA81) that better mimics the reservoir rock pore geometry, to visualize the oil films in different spreading systems. NOA81 is a transparent polymer with high chemical and physical resistance, which enabled the device to withstand harsh organic solvents as well as high pressures and temperatures encountered in the EOR experiments. This device was designed with pore network similar to that of a consolidated water wet porous rock with varying channel widths and taper, unlike various other platforms using regular square or constant channel width grids. This modification resulted in a more realistic representation of the actual pore network of reservoir rocks. Continuous thinner oil films were observed in the positive spreading system, whereas discontinuous trapped oil blobs were encountered in the negative spreading system. Statistical analysis carried out on the thickness of the oil phase separating water and gas phases indicated significant differences and confirmed the visual observations.

Static adsorption and mathematical model applied in EOR using a supramolecular surfactant

Typical adsorption isotherms show the characteristic Langmuir behavior. However, in the presence of a supramolecular surfactant, its corresponding adsorption isotherms, exhibiting atypical decrement behavior. The static adsorption results on limestone and dolomite show maximum values of 2.40 and 5.98 mgsurfactant/grock, respectively. For explaining this behavior, was developed a new modified mathematical adsorption model, (dГdt)ads=kadsc(Г∞−Г)−kcmc(c−ccmc)nГH(c−ccmc). This model describes the adsorption isotherms in two regions: the first one corresponds to the conventional adsorption increase and the second to decay adsorption phenomena. This decrement behavior is mainly due to the ultra-high salinity and the monomer ⇆ micelle ⇆ vesicle equilibrium in connate water.The new model shows the better fitting with r2 = 0.9743 for limestone and r2 = 0.9668 for dolomite, respect to the Langmuir model r2 = 0.8556. Which represents the accuracy with the experimental values in the adsorption isotherm.Also, it is highlighted the significance of the information provided by the new static adsorption Langmuir mathematical model. That establishes criteria for using a chemical in enhanced oil recovery processes.From the data in the adsorption profile, the optimal concentration for the adsorption process occurs between 1800 and 2000 ppm of supramolecular surfactant. The enhanced oil recovery experiment in ultra-high salinity and hardness is better with an increase in the temperature: 8% at 80 °C, 15% at 90 °C and 20% at 100 °C.

Novel laboratory investigation of huff-n-puff gas injection for shale oils under realistic reservoir conditions

Enhanced oil recovery (EOR) from shale oil formations is recognized as the next frontier in the exploitation of unconventional resources. Current approaches for performing EOR experiments using fractured rocks can generate misleading results as the fractured cores cannot be saturated with live oils. In this work, a novel laboratory methodology is developed to quantify the efficiency of gas huff-n-puff in shale oil formations under realistic reservoir conditions, i.e. live oil and hydraulic fracturing reservoir conditions. This new approach involves first saturating the shale core with oil and then hydraulic fracturing the oil-saturated core by increasing pore pressure above the core confining pressure. To demonstrate the viability of this new methodology, shale cores from the Haynesville formation with a permeability of 0.0001 mD were tested.Two huff-n-puff experiments were performed by the injection of associated gas into cores saturated with either dead crude oil or live oil. 48% additional oil recovery was achieved from the shale core saturated with live oil whereas, the shale core saturated with dead oil yielded a 33% enhanced oil recovery, which is significantly lower than that of the live oil. Furthermore, the pressure decay profiles during the soaking periods indicate a comparatively higher gas penetration into the live oil system despite the higher gas solubility in the dead oil. The in-situ gas formation can have a strong influence on the efficiency of huff-n-puff. The notable differences in the results obtained on live compared to dead oil experiments demonstrate the need to perform more realistic laboratory experiments to better optimize shale oil EOR-based extractions in the field.

Effect of aluminum oxide nanoparticles on the rheology and stability of a biopolymer for enhanced oil recovery

Uncommon and untested biopolymers in field pilot studies, but applied in laboratory studies are combined with Al2O3 nanoparticles to form nanocomposites for enhanced oil recovery (EOR) performance evaluation. Core plug samples of the Niger Delta region and Berea sandstone were used as the porous media for EOR experiments. Incremental oil recovery sequel to waterflooding (secondary recovery) was 5–12% and 5–7% for potato starch nanocomposite (PSPNP) and gum Arabic nanocomposite (GCNP) respectively. The biopolymer nanocomposites showed improved viscosity over the biopolymers. Thus, the nanoparticle served as a viscosity modifier on one-hand and stability enhancer on the other. EOR was affected by biopolymer and nanoparticle concentration with the attendant catch-22 situation of permeability impairment. The overall higher incremental recovery of applying PSPNP came by an intermediate potato starch (PSP) flooding between waterflooding and PSNP flooding. Consequently, slugs of biopolymer and biopolymer nanocomposite may be the way forward knowing that the biopolymers studied have surface-active constituents.

Performance of Air Injection vs. CO2/Water Injection in a Tight, Light-Oil Reservoir: A Laboratory Study

Summary This paper outlines the results of an early-stage comparative study of air-injection-based and immiscible-carbon-dioxide (CO2)/water-injection-based enhanced-oil-recovery (EOR) processes for a 30+ °API tight, light-oil reservoir. This was accomplished by embedding multiple low-permeability core plugs in crushed reservoir-core material to create a composite core that was contained in a 1.84-m-long core holder. The objectives of this unscaled experimental work were to understand the suitability of each EOR process for a low-permeability reservoir; to define process parameters before a potential field pilot; and to understand the relative merits of each EOR process to mobilize light oil from a tight matrix to a fracture network. A detailed experimental investigation was conducted at realistic reservoir conditions to evaluate the feasibility of an air-injection-based EOR process. The air-injection results were compared with those from an immiscible CO2/water-injection EOR experiment using the same experimental setup and reservoir conditions. Both the air- and CO2/water-coreflood tests were performed at 10 340 kPag (1,500 psig) and 99°C in a 100-mm diameter, 1.84-m-long composite-core holder using 38-mm-diameter reservoir core plugs (that represented the matrix) mounted within the crushed reservoir-core material (that represented the fracture); inert helium gas was used to pressure up the core holder to reservoir pressure. Permeability of the core plugs was from 0.3 to 3 md, while the permeability of the crushed core material was 1 to 3 darcies. Air injection was performed as a standard, one-dimensional combustion-tube test with injection of 2.3 pore volumes (PVs) of air to burn 71% of the packed core length (including helium, a total of 4.3 PV of gas injected). The CO2/water coreflood was performed with the injection of 2.86 PV of CO2 followed by an extended soak period, then a second injection of an additional 2.86 PV of CO2, followed by the injection of 2.6 PV of water. The pretest and post-test core-plug measurements of oil saturation show that the air-injection process removed significantly larger quantities of hydrocarbons than the immiscible-CO2/water-injection process. Relative to the initial conditions of the core plugs for the air-injection experiment, more than 95% of the hydrocarbons were removed (note that some fraction of original oil was consumed as fuel). In the post-test CO2/water-injection core plugs, oil recovery was in the range of 30 to 55% of initial oil in place (IOIP). These findings suggest that, under an appropriate field design, both processes have the potential to recover incremental oil from tight reservoirs. However, the air-injection process might be better suited to mobilize oil, because of thermal expansion, than the CO2/waterflood process.

Experimental investigation of enhancement of carbon dioxide foam stability, pore plugging, and oil recovery in the presence of silica nanoparticles

The influence of surface-modified silica (SiO2) nanoparticles on the stability and pore plugging properties of foams in porous media was investigated in this study. The pore plugging ability of foams was estimated from the pressure drop induced during foam propagation in porous media. The results clearly showed that the modified SiO2 nanoparticle-stabilized foam exhibited high stability, and the differential pressure increased in porous media by as much as three times. The addition of SiO2 nanoparticles to the foaming dispersions further mitigated the adverse effect of oil toward the foam pore plugging ability. Consequently, the oil recovery increased in the presence of nanoparticles by approximately 15% during the enhanced oil recovery experiment. The study suggested that the addition of surface-modified silica nanoparticles to the surfactant solution could considerably improve the conventional foam stability and pore plugging performance in porous media.

Fast spatially-resolved T2 measurements with constant-gradient CPMG

Speed of acquisition is paramount for the application of magnetic resonance to flow experiments through porous rocks. One popular method for imaging core floods is the spatially resolved T2 experiment which can separate fluids either by their viscosity contrast or by doping one fluid with a relaxation agent. Existing techniques for spatial-T2 may suffer from long acquisition times and eddy currents due to the pulsing of magnetic field gradients. Here, we propose a constant gradient method for 1d spatially-resolved T2 which embraces the speed of frequency encoding techniques and avoids eddy currents by the absence of any gradient ramps during the radio frequency (r.f.) pulse train. We provide the operating envelope for this kind of experiment, which is restricted due to the slice selectivity of the r.f. pulses in the presence of the magnetic field gradient. Additionally, we show that the effects of self-diffusion and the mixing of T1 and T2 contributions are manageable. As an illustration, we have applied this technique to an enhanced oil recovery experiment. The two fluid phases were tracked without any doping and with a time resolution of 40 s. In this case, the increased time resolution allowed us to observe dynamic flow phenomena such as fluid fingering and the calculation of the velocity of the fluid displacement fronts.

Comparison of in-situ and ex-situ microbial enhanced oil recovery by strain Pseudomonas aeruginosa WJ-1 in laboratory sand-pack columns

ABSTRACTMicrobial enhanced oil recovery (MEOR) applies biotechnology to improve residual crude oil production from substratum reservoir. MEOR includes in-situ MEOR and ex-situ MEOR. The former utilizes microbial growth and metabolism in the reservoir, and the latter directly injects desired active products produced by microbes on the surface. Taking biosurfactant-producing strain Pseudomonas aeruginosa WJ-1 for research objects, in-situ enhanced oil recovery and ex-situ enhanced oil recovery by biosurfactant-producing strain WJ-1 were comparatively investigated in sand-pack columns.The results showed that P.aeruginosa WJ-1 really proliferated in sand-pack columns, produced 2.66 g/L of biosurfactant, altered wettability, reduced oil-water interfacial tension (IFT) and emulsified crude oil under simulated in-situ process. Results also showed that higher biosurfactant concentration, lower IFT, smaller average diameters of emulsified crude oil were obtained in in-situ enhanced oil recovery experiment than those in ex-situ enhance oil recovery experiment. Similar wettability alteration was observed in both in-situ and ex-situ enhanced oil recovery experiment. The flooding experiments in sand-pack columns revealed that the recovery of in-situ was 7.46%/7.32% OOIP (original oil in place), and the recovery of the ex-situ was 4.64%/4.49% OOIP. Therefore, in-situ approach showed greater potential in enhancing oil recovery in contrast with ex-situ approach. It is recommended that the stimulation of indigenous microorganisms rather than injection of microbial produced active products should be applied when MEOR technologies were employed.

Investigation on matching relationship between dispersed particle gel (DPG) and reservoir pore-throats for in-depth profile control

The current study aims at in-depth profile control to further improve oil recovery by studying the matching relationship between the size of dispersed particle gel (DPG) and geometry of reservoir pore-throat. The DPG products with different sizes were prepared, and their microscopic characteristics and particle size distributions were analyzed. The matching factor, which was defined as the ratio of average size of DPG particles to mean size of pore-throats, was introduced to represent the matching relationship. The injection properties and plugging capacities were systematically studied by a series of core flooding experiments to optimize the matching factor. The matching factor was optimized from 0.21 to 0.29 depending on both the injection pressure and the plugging rate. In addition, the results of multi-point pressure measurement experiment verified that the DPG particles exhibited good in-depth migration and plugging ability within the optimized matching factor values. Meanwhile, scanning electron microscope (SEM) was used to study the distribution of DPG particles in porous media. The results intuitively showed that the DPG particles can migrate to the deep of porous media and induce effective plugging to the pore-throats. Moreover, the enhanced oil recovery experiments for different matching factors were conducted, and the mechanisms for enhanced oil recovery by DPG with different matching factors were proposed. The enhanced oil recovery with an optimized matching factor was much higher than that with a smaller or larger matching factor. Owing to good in-depth migration and plugging ability of DPG particles with optimal matching factors, the subsequent injected water was diverted into low permeability zones with high oil saturation and, consequently, widely swept the remaining oil in low permeability zones.

The Application of Nanofluids for Enhanced Oil Recovery: Effects on Interfacial Tension and Coreflooding Process

Most oil reservoirs around the world are experiencing their second half of life. Hence, the necessity of appropriate enhanced oil recovery (EOR) method as a more efficient technology gets further importance. Nanotechnology is an advanced technology that has proved its potential to enhance oil recovery. In this study, some selected types of nanoparticles were used, which were aluminum oxide, iron oxide, and silicon oxide treated by silane, as EOR agents during different flooding scenarios and EOR experiments under surface conditions. For the first time, the application of propanol as a dispersing agent of nanoparticles and EOR agent in the formation was investigated by this research work. In order to examine the recovery mechanisms of nanofluids, interfacial tension (IFT), and contact angle measurements between different concentrations of nanofluids and crude oil were measured. Then, several coreflood experiments were conducted to investigate their impacts directly on recoveries. The experiment results show that the nanofluids can decrease the IFT between water and oil phases and make the solid surface more neutral wet. Results indicate that aluminum oxide and silicon oxide treated by silane are good agents for enhanced oil recovery, while silicon one changes rock wettability more in addition to reduction of interfacial tension between oil and water. According to the results the future expectation is that these nanoparticles with their dispersing agent could mobilize more oil in the pore network at field scale to improve oil recovery.

Microwave Synthesis of ZnO Nanoparticles for Enhanced Oil Recovery

Synthesising zinc oxide nanoparticles to get certain specific characteristics to be applied in Enhanced oil recovery (EOR) is still challenging to date. In this work, zinc oxide (ZnO) nanoparticles were synthesised using the sol-gel method by dissolving zinc nitrate hexahydrate in nitric acid. The ZnO crystal and particles morphology and structure were determined using X-ray Diffractometer (XRD) and Field Emission Scanning Electron Microscope (FESEM). In this study, a microwave oven was used for annealing ZnO without insulating a sample in any casket. The results show that 30 and 40 minutes of annealing and stirring for 1 hour influenced the morphology and size of zinc oxide particles in nanoscale. These parameters could be tailored to generate a range of nanoparticle morphology (agglomerated nanoparticles in a corn-like morphology), a crystal size with the mean size of 70.5 and 74.9 nm and a main growth at the peak [10. EOR experiment were conducted by dispersing 0.10 wt% ZnO NPs in distilled water to form a ZnO nanofluid. Then the fluid was injected into the medium in the 3rd stage of the oil recovery to present EOR stage. It was found that ZnO nanofluid has the ability to extract 8% of the original oil in place (OOIP).

Enterobacter cloacae as biosurfactant producing bacterium: Differentiating its effects on interfacial tension and wettability alteration Mechanisms for oil recovery during MEOR process

Microbial enhanced oil recovery (MEOR) process utilizes microorganisms or their metabolites to mobilize the trapped oil in the oil formation after primary and secondary oil recovery stages. MEOR technique is considered as more environmentally friendly and low cost process. There are several identified mechanisms for more oil recovery using MEOR processes however; wettability alteration and interfacial tension (IFT) reduction are the important ones. Enterobacter Cloacae, a facultative bio-surfactant producer bacterium, was selected as a bacterial formulation due to its known performance on IFT reduction and wettability alteration. To quantify the effects of these two mechanisms, different tests including oil spreading, in situ and ex situ core flooding, wettability measurement (Amott), IFT, viscosity and pH measurements were performed. The obtained results revealed that the experimental procedure used in this study was able to quantitatively identify the individual effects of both mechanisms on the ultimate microbial oil recovery. The results demonstrated considerable effects of both mechanisms on the tertiary oil recovery; however after a proper shut in time period, more tertiary oil was recovered because of wettability alteration mechanism. Finally, SEM images taken from the treated cores showed biofilm formation on the rock pore surfaces, which is responsible for rock surface wettability alteration.

Using the value of the crosscorrelation coefficient to locate microseismic events

A procedure to locate seismic events uses the value of the crosscorrelation coefficient between waveforms of different events. First, an empirical relation between spatial event separation and maximum crosscorrelation coefficient is established for a subset of a priori located reference events. Then this relation is used to determine the hypocenters of an increasing number of events by a grid-search strategy. Measured arrival-time differences between S- and P-waves also constrain the location. Although the reference events are located by a standard method using the arrival-time measurements at three or more receivers, the correlation-based location requires only one receiver. The method has been applied to microseismic data recorded at a single borehole sensor during the 2004/05 injection experiment at the Continental Deep Drilling Site (KTB) in Germany. With the approach, significantly more weak seismic events were located, compared to the number of events recorded by a near-surface receiver array and by inversion of arrival times. The proposed location method is particularly well suited to locate small-magnitude earthquakes within dense event clouds when too few arrival-time observations for part of the events are available and standard location methods fail. These conditions are frequently met in the case of microseismic monitoring of geothermal or enhanced oil recovery experiments.

Numerical modeling of surface-to-borehole electromagnetic surveys for monitoring thermal enhanced oil recovery

Electrical conductivity is an important petrophysical property used to predict lithology and fluid content in petroleum reservoirs. Conductivity distribution between wells can, in principle, be mapped with electrical or electromagnetic (EM) techniques when sources or receivers (or both) are located in the wells. Unfortunately, the resolution of these methods is relatively poor. Resolution is improved, however, in monitoring applications where the response of a dynamic reservoir process is recorded at different times and compared. Examples of such dynamic processes are fluid replacement during primary production, secondary recovery, and enhanced oil recovery (EOR) techniques as fireflooding, steamflooding, and CO 2 flooding. Such measurements can be made with technology currently available within the geophysical industry and at relatively low expense. A numerical model study of the Holt Sand in situ combustion EOR experiment was conducted to test the feasibility of electromagnetically monitoring the progress of the advancing fire flood. The resistivity and geometry of the burn zone was obtained from pre-burn and post-burn well log data. The study shows that the surface-to-borehole electromagnetic method detects a clear signature from changes in resistivity of the burned reservoir horizon from distances as great as 100 m. Similar conclusions hold for steam flood processes. An important phenomenon which complicates interpretation of EM monitoring of thermal EOR processes is a zone of decreased resistivity adjacent to the reservoir horizon caused by conduction of heat into the bounding shales.

Firefood Microseismic Monitoring: Results And Potential For Process Control

Abstract A pilot fireflood in a 750m deep high permeability unconsolidated channel sand in eastern Alberta was instrumented for microseismic emission to evaluate the technique for in-situ process monitoring. The pilot consists of a central air injection well, eight surrounding production wells on artificial lift, and two internally placed observation wells. Three surface geophones and a downhole 12-hydrophone string in a single well were deployed. Data were collected for 22 hours. Event detectors and cassette recorders were used for data collection. The recorders are triggered by a preset signal-to-noise ratio, allow pre- and post-event buffer recording, and can record 200 samples per second. The devices are self-triggering so that one large signal automatically causes recording on other channels. Monitoring during twelve hours of steady air injection at 625m3/s yielded a clear event frequency of about 50 events/h. The events are mostly clear compressional wave arrivals, each consisting of 1 to 2 cycles with a repeat signal, in-phase with the first, occurring shortly afterwards (0.2–0.3 sec later). Stopping air injection caused a gradual drop in event frequency, and the rate was re-established when air injection was continued. The surface geophone yielded no useful data associated with in-situ processes. Spectral frequency analysis and knowledge of material properties indicated that the events are shears of a stick-slip nature associated with the strain weakening behavior of the over-compacted reservoir sands. The recording accuracy implies a capability to locate events to within 10m in space, and signal analysis indicates that some discrimination between events as a function of processes may be achieved. The system is therefore directly applicable to mapping of firefloods and can thus be used as an aid to process control. Other in-situ recovery technologies may also produce useful signals for process control. In particular, steam flooding, hydraulic fracturing, and high-pressure injection operations likely generate mappable microseismic events which can be applied directly to production/injection strategy. Introduction As part of an ongoing program of studies relating to the process of fireflood recovery of heavy oil. Noreen Energy Resources Ltd. and the University of Alberta have monitored a fireflood with a vertical string of Mark Products T27 hydrophones in an observation well very close to the burn zone. An enhanced oil recovery experiment is being carried out in the Bodo pool at a depth of 750m in east-central Alberta. A fireflood scheme is active using a central air injection well and eight peripheral wells in a square pattern on pump. The air injection rate is 625m3 /h and the pattern contains two observation wells monitored for temperature changes. The project (Fig. 1) was monitored for microseismic activity for a 22-hour period in the spring of 1981 using a string of hydrophones in one observation well and a set of three surface geophones. The purpose of the microseismic experiment was to find out if seismic energy was being emitted as the result of the process, and to assess whether this energy could be used to clarify in-situ processes and ultimately be applied to aid process control by delineating fire flood fronts and velocities.