Manouchehr Haghighi

Visualization of steam displacement of heavy oils in a Hele-Shaw cell☆

Abstract Experimental visualization of steam injection was performed at low pressure in a transparent Hele-Shaw cell. Synthetic (Dutrex 739) and natural heavy oils were displaced by steam under a variety of conditions. The results demonstrate the significant interplay between steam injection, steam condensation, viscous fingering, heat transfer, gravity and steam distillation effects. The experiments reveal that steam fronts may be neither smooth nor flat, but undergo constant rearrangements as a result of condensation and injection. These dynamics are substantially different from typical immiscible displacement processes. The injected steam was generally found to follow the path of the condensed water. The latter set the general displacement pattern, which was highly fingered. Also identified was a rather unusual viscoelastic response of the displaced heavy oils. Although novel and interesting, these results should be extrapolated with care to account properly for field effects of heat losses.

Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

Visualization of Micro-Particle Retention on a Heterogeneous Surface Using Micro-models: Influence of Nanoscale Surface Roughness

Nanoscale surface roughness and charge heterogeneity have been widely recognized to influence particle retention in porous media under unfavourable chemical conditions such as solutions of low ionic strength (IS) or high pH. However, previous researches have not appreciated the influence of nanoscale surface roughness on particle retention under favourable chemical conditions (e.g. high solution IS). This information is needed to better understand and predict particle transport and retention in such natural environments, such as enhanced oil recovery in a high-salinity reservoir. A glass-etched micro-model was employed to directly visualize retention of micro-sized particles and their spatial distribution on the glass surface under various chemical conditions. The extended DLVO calculations accounting for the effect of nanoscale surface roughness on the interaction energies were employed to quantitatively evaluate the experimental results. It was shown that nanoscale roughness on solid surfaces significantly reduced the strength of primary minimum attachment when the solution IS was high. In particular, increasing the density of roughness on the solid surface increased the strength of primary minimum, whereas increasing the roughness height decreased the strength of primary minimum interaction. Consequently, retained particles in the primary minimum are expected to be susceptible to detachment via hydrodynamic drag forces and movement of air–water interfaces during transient in water saturation (e.g. drainage or imbibition). Indeed, results obtained from the micro-model experiments demonstrated that only a fraction of solid surface was available for particle retention even at a very high IS of 0.6 M.

Visualization of steam injection in fractured systems using micromodels

We present visualization studies of hot water and steam injection in micromodel geometries that mimic a matrix-fracture system. Emphasis is placed on the matrix-fracture interaction during steam injection. We visualize the movement of steam and determine the conditions under which matrix penetration by steam occurs. More generally, the effectiveness of steam injection in displacing oil from the matrix is assessed. Displacement of oil was observed to occur by three mechanisms : a thermally-induced solution gas-drive, capillary imbibition of condensed water and displacement by steam, when the latter penetrated the matrix. Vaporization of light components at elevated temperatures generated an efficient solution-gas drive in the matrix, without the need for steam penetration. This also led to the formation of stable foam-like lamellae, which improved oil production by blocking the movement of steam and water in the fracture. This mechanism was also found to apply during hot water injection. Condensed water imbibed the matrix according to rules that govern imbibition of a fracture-matrix system. Steam penetration of the matrix occured when the steam rate exceeded a critical value, determined from drainage considerations. The results should be useful in modeling of steam injection in naturally fractured reservoirs.

Production Data Analysis in Eagle Ford Shale Gas Reservoir

ve analysis technology to analyse the production behaviour and to estimate the essential parameters for this reservoir. This type curve was constructed based on transient production rate with constant well pressure in a closed boundary of stimulated reservoir volume (SRV) with double porosity approach. In order to analyse the early production data we used Bello’s and Nobakht’s approach to account for apparent skin. In this study, three flow regimes were identified consisting of 1- bilinear flow; 2- matrix linear flow; and 3- boundary dominated flow. For the analysis of early flow regime, two possibilities of transition flow and apparent skin have been considered. First, the fracture permeability was estimated to be around 820 nano Darcy based on transition flow analysis. Second, the matrix permeability was estimated to be either 181 or 255 nano Darcy based on two different approaches in matrix linear flow regime. Furthermore, original gas in place (OGIP) and SRV were estimated from the boundary dominated flow regime. To validate the estimated matrix permeability, a single porosity numerical model with high permeability transverse fractures was built to match the production history. The permeability from simulation was in a good agreement with type curve analysis. Production forecasting has also been carried out using different adsorption isotherms. The results showed that the effect of desorption depends on the reservoir pressure and the shape of adsorption isotherm curve. In early time of production, desorption is usually not effective, however, for long-term production forecasting, it is necessary to account for this phenomenon by providing an accurate isotherm

Laboratory Studies of MEOR in the Micromodel as a Fractured System

Microbial enhanced oil recovery (MEOR) is receiving renewed interest worldwide in recent years as a viable method while not damaging the reservoir is proven to be remarkably effective, however to some extent costly. This method is based on microorganisms’ activities to reduce residual oil of reservoirs, which is dependent on behavior of inherent microorganisms or injection of bioproduct of external microorganisms. In this work, five bacterial species were taken from MIS crude oil that is one of the aging Persian fractured reservoirs. These microorganisms are substantially strong in increasing oil recovery especially by reducing IFT and other MEOR mechanisms such as change of wettability of rock at the favorable condition for the activities of these bacteria observed within the temperature range of 50°C to 90°C at the atmospheric pressure. Two series of visualization experiments were carried out to examine the behavior of microbial enhanced oil recovery in micromodels designed to resemble the fractured system: static and dynamic. In the static one, carbonate rock-glass micromodel is used to simulate the reservoir conditions and the latter is performed by a glass micromodel which has a fracture with 45 degree inclination. The image processing methodology is used to determine the recovery achieved by MEOR in the micromodel made of glass.

Optimization of the Production of Biosurfactant From Iranian Indigenous Bacteria for the Reduction of Surface Tension and Enhanced Oil Recovery

Abstract The optimum conditions for biosurfactant production by Irans isolates were examined. The Taguchi method was used to identify nutritional requirements in the medium using four parameters; that is, carbon source, nitrogen, phosphorous, and salt concentrations. The use of whey, oil, and sucrose as carbon sources; NaCl as salt source; (Na2HPO4, NaH2PO4) as phosphorous source; and (NH4)2SO4 as nitrogen source was examined to determine bacteria optimum conditions. According to the Taguchi method using the sucrose source, the optimal conditions for Bacillus subtilis were 50 g/L NaCl, 13.53 g/L (Na2HPO4, NaH2PO4), and 1 g/L (NH4)2SO4; for Bacillus cereus they were 25 g/L NaCl, 13.53 g/L (Na2HPO4, NaH2PO4), and 1 g/L (NH4)2SO4; and for Pseudomonas putida they were 25 g/L NaCl, 13.53 g/L (Na2HPO4, NaH2PO4), and 1 g/L (NH42SO. Oil displacement experiments in the micromodel at optimum conditions showed around 25% recovery of residual oil with added supernatant of Bacillus subtilis.

Design and optimisation of multi-stage hydraulic fracturing in a horizontal well in a shale gas reservoir in the Cooper Basin, South Australia

The APPEA Journal is multidisciplinary technical journal documents peer-reviewed papers presented at APPEA’s Annual Conference. From 2008 onward the APPEA Journal is available in DVD format only produced by: Media Dynamics.

Production and optimization of microbial surfactin by bacillus subtilis for Ex situ enhanced oil recovery

In the research, biosurfactant production and the optimization of biosurfactant production conditions have been examined have been examined using one strain of Bacillus subtilis isolated from agricultural soil. For biosurfactant production, the optimum conditions were sucrose as carbon source, temperature at 37°C and 250 rpm. At 250 rpm, the optimum filling volume of culture media in a 500 mL Erlenmeyer flask was determined as 100 mL. The results show that shaking the flask should increase the oxygen transfer rate from gas phase to liquid phase, but if the filling volume of culture media is more than 100 mL, the oxygen limitation will be governed on the culture medium which results in the reduction of biomass and biosurfactant at 250 rpm. The oxygen limitation causes 23% and 18% reductions of biomass and biosurfactant, respectively. The biosurfactant produced also attained emulsion indexes as 80%, 75%, 68%, and 65% for crude oil, hexadecane, kerosene, and diesel, respectively. Oil displacement experiments in micromodel with kerosene show 25% higher recovery rate in residual oil using the proposed biosurfactant.

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

Y. Fei, M.E. Gonzalez Perdomo, V.Q. Nguyen, Z.Y. Lei, K. Pokalai, S. Sarkar and M. Haghighi