Postdoctoral Research Associate
I am a computational geoscientist and a petroleum engineer. I am interested in coupled multi-physics processes of flow, transport, and mechanical deformation in porous media. Applications are in the areas of enhanced oil recovery, groundwater remediation, induced seismicity, and microfluidics. I emphasize a mathematical and computational approach in studying geophysical systems to identify the dominant coupling mechanisms and expressing them in the form of reduced-order models.
I received my masters in Petroleum Engineering from Stanford University and my PhD in Civil and Environmental Engineering from MIT. I have worked for more than six years in the oil and gas industry as a reservoir engineer. My experience is in waterfloods, CO2 floods, tight gas, and solution-gas drive reservoirs in US, India, and New Zealand.
Currently, I am pursuing research in three directions:
 Assessment and mitigation of the risk of induced seismicity during extraction of oil and gas, groundwater, and geothermal resources
 Development of new computational frameworks for modeling coupled processes in the earth
 Reservoir characterization and property estimation using joint inversion
I am a co-instructor for the following courses: 1.723 Computational Methods for Flow in Porous Media (Graduate), 1.000 Computer Programming for Scientific and Engineering Applications (Undergraduate).
 B. Jha, F. Bottazzi, R. Wojcik, M. Coccia, N. Bechor, D. Mclaughlin, T. A. Herring, B. H. Hager, S. Mantica, R. Juanes. Reservoir characterization in an underground gas storage field using joint inversion of flow and geodetic data. Submitted.
 C. Nicolaides, B. Jha, L. Cueto-Felgueroso, R. Juanes. Impact of viscous fingering and permeability heterogeneity on fluid mixing in porous media. Accepted in Water Resources Research.
 B. Jha, R. Juanes. Coupled modeling of multiphase flow and fault poromechanics during geologic CO2 storage. Energy Procedia, 63, doi:10.1016/j.egypro.2014.11.360, 2014.
 B. Jha, R. Juanes. Coupled multiphase flow and poromechanics: a computational model of pore-pressure effects on fault slip and earthquake triggering. Water Resources Research, 50, doi:10.1002/2013WR015175, 2014.
 B. Jha, L. Cueto-Felgueroso, R. Juanes. Synergetic fluid mixing from viscous fingering and alternating injection. Physical Review Letters, 111, 2013.
 B. Jha, L. Cueto-Felgueroso , R. Juanes. Quantifying mixing in viscously unstable porous media flows. Physical Review E, 84, 2011.
 B. Jha, L. Cueto-Felgueroso, R. Juanes. Fluid mixing from viscous fingering. Physical Review Letters, 106, 2011.
 B. Jha, R. Juanes. A locally conservative finite element framework for the simulation of coupled flow and reservoir geomechanics. Acta Geotechnica, 2, 2007.
 Best Doctoral Thesis Award, Civil and Environmental Engineering, MIT, 2014
 Outstanding Student Paper Award, Hydrology, American Geophysical Union Fall Meeting, 2010
 Outstanding Student Paper Award, Hydrology, American Geophysical Union Fall Meeting, 2009
 Schoettler Fellowship, Civil and Environmental Engineering, MIT, 2009
 Knowledge-In-Action Award, Schlumberger, 2003
 Oil India Medal from the Mining, Geological and Metallurgical Institute of India, 2002
 Gold Medal, Petroleum Engineering, Indian School of Mines, 2001
My research contributions are in the following fields:
CO2 sequestration in a reservoir requires assessment of the risk of inducing slip on pre-existing faults due to overpressurization. Fault slip (left) and rupture velocity (right), for a synthetic case designed to induce fault slip, are shown below.
Cross-section (x-z) view of vertical displacement field in a faulted geologic basin. Aquifer is overpressurized due to carbon dioxide injection, which leads to rupture on a normal fault and subsequent earthquake. Shown below is the vertical displacement after the fault slip.
Production of oil and gas from faulted reservoirs requires coupled flow and geomechanical modeling in order to assess the risk of inducing fault instability from production and injection in the field. The change in the Coulomb stress on a fault in a real oilfield in Italy due to 32 years of production and injection is shown below.
Computational models for coupled multiphase flow and deformation
The coupling between subsurface flow and geomechanical deformation is critical in the assessment of the environmental impacts of groundwater use, underground liquid waste disposal, geologic carbon dioxide storage, and exploitation of shale gas reserves. In particular, seismicity induced by fluid injection and withdrawal is a matter of public concern. We develop new computational frameworks to model coupled multiphase flow and geomechanics of faulted reservoirs.
Featured on Computational Infrastructure for Geodynamics webpage and in their August 2014 Newsletter
Hydraulic fracturing of a naturally fractured reservoir requires careful design of the fracturing operation to maximize the stimulated reservoir volume by establishing connection between fractures. Below is a simulation of a single hydraulic fracture.
Vertical displacement for uncoupled (left) and coupled (right) simulations in a 12km x 6km x 4km aquifer with two oblique faults. Slip prescribed on the faults through rupture events at every 200 yr interval and creep events. Boundary conditions: zero x and y displacements at x+ and x- faces, bottom boundary fixed. For the coupled case, wells are at constant pressure. Initial condition: lithostatic stress, hydrostatic pressure. Grid is distorted with displacements magnified by a factor of 80.
Reservoir characterization using joint inversion
Reservoir characterization refers to the estimation of spatial distributions of rock and fluid properties in the reservoir, such as porosity, permeability, and compressibility. Joint inversion of flow data (from wells) and surface deformation data (from GPS and InSAR satellites) is used for statistical estimation of rock properties in a coupled flow and geomechanical model of a real reservoir shown below.
Fluid mixing in porous media
Mixing of fluids is an important and complex phenomenon. It controls many natural and industrial processes. Fluid mixing in porous media and in low Reynolds number flows is especially difficult because of the absence of turbulence. Development and control of mixing in such flows is a challenge and an active area of research.
Mixing from viscous fingering
In enhanced oil recovery techniques such as miscible gas flooding where CO2 is injected to mix with and mobilize crude oil, recovery efficiency can be increased by developing miscibility between the two fluids. We show that viscous fingering, a type of hydrodynamic instability, can be used to induce disorder in the flow and thereby enhance mixing. Tip-splitting and channeling during viscous fingering are two different mechanisms of mixing. Shown below is a snapshot of the mixture concentration field during flow of a less viscous fluid (light color) displacing a more viscous fluid (dark color).
We develop a two-equation model for the concentration variance and mean scalar dissipation rate to quantify the evolution of the degree of mixing in a viscously unstable displacement. Fastest mixing is achieved by optimizing the interplay between tip-splitting and channeling mechanisms during viscous fingering. Shown below is a snapshot of the concentration field during flow of the less viscous fluid, initially distributed as blobs, through a more viscous ambient fluid in a periodic domain.
Stokes flow in a Hele-Shaw cell serves as a simple analog for porous media flows. We study spreading and mixing of slugs of different viscosities flowing between two parallel glass plates. Shown below are the concentration fields of slugs of three miscible fluids--red, blue, and green. Ratio of viscosities: blue/red = 55, green/blue = 5. Initial placement of slugs is shown in the top figure. More mobile red fluid flows through the less mobile blue fluid.
Mixing during slug injection
Mixing at low Reynolds number can be enhanced by alternating injection of slugs of different viscosities. This is relevant for achieving fast mixing in microfluidic devices as well as during miscible CO2 flooding. We show that the synergetic action of alternating injection and viscous fingering leads to a dramatic increase in mixing efficiency. Top: mild viscosity contrast, Middle: strong viscosity contrast, Bottom: optimum viscosity contrast.
Mixing and dilution in heterogeneous formations
Heterogeneity of the porous medium is another source of disorder in the flow that causes spreading and dilution of groundwater contaminants. Shown below are the concentrations of a contaminant in a vertical section through an aquifer with groundwater flow. Initially, the contaminant started as a thin slug (light color) instantaneously placed in the background flow of water (dark color). The flow direction is from left to right. Fluid properties of the contaminant and water are identical. Top: mildly heterogeneous medium, Bottom: strongly heterogeneous medium.
Concentration field during transport of two passive tracers (blue and red colors) with the groundwater (green) flow. The flow direction is from left to right.
Displacement of a contaminant (fluid 2 in the figure below), with viscosity higher (middle) or lower (right) than the ambient fluid, depends strongly on the interplay between viscous fingering and permeability-based heterogeneity. Spatial structure of the plume, mixing and chemical reaction within the domain, and breakthrough characteristics at the outflow well are determined by this interplay.