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  • Choke management to minimize proppant crushing
  • Bean-up protocols to avoid sand production or proppant flowback
  • Bean-up and shut-down protocols to prevent fines migration or wellbore collapse.
  • Automatic adjustment of gas-lift valves to maximize production
  • Control of ESP frequency to maximize liquids production
  • Integration of production and reservoir data for dynamic nodal analysis
  • Artificial lift design and optimization
  • Maximize Revenue: Maximize production rates while satisfying completion, reservoir and surface equipment constraints.
  • Provide well operators or automated well control systems with operational recommendations.
  • Reduce Costs: Minimize man hours by efficiently coupling simulation tools.
  • Minimize the risk of completion failures which may result in costly workovers and down time.
  • Identify production bottlenecks.
  • Dynamic fracture propagation based on reoriented subsurface stresses
  • Injectivity decline due to suspended particles in the injected water which plug the formation.
  • Changes in fluid saturations, temperature and stresses in multiple injection / production wells and associated oil recovery with growing fractures.
  • Simultaneous simulation of two phase flow in the reservoir with coupled geomechanics and arbitrary fracture propagation.
  • Non-isothermal conditions.
  • Implicit coupling with fracture propagation model
  • Application of particle filtration and plugging physics to simulate injectivity decline
  • 3-D fracture propagation
  • Multiple injectors, multiple fractures
  • Multi-layered reservoirs

  • Geo-mechanical reservoir simulation

More information:

 

  • Energized hydraulic fracturing (using gases and other fluids)

Current practices in energized treatments, using gases such as N2, CO2 and foams, remain rudimentary in comparison to other fracturing fluid technologies. None of the available 3-D fracturing models are able to capture the thermal and compositional effects that are important when using energized fluids.

  • A wellbore model which relates bottom-hole and surface variables (pressure, temperature, proppant concentration and rates).
  • A well productivity model that allows a comparison of different frac fluids and fracture designs.
  • Accurate proppant transport model which considers hindered settling and proppant retardation effects.
  • Thermal and fluid compressibility effects are considered to model compressible fracturing fluids.
  • Multiple layers with different stress and mechanical properties to estimate height growth.

  • Pad fracturing (parent-child well interference)

  • Multiple well fracture interference
  • Infill drilling
  • Fracturing chile dwells
  • Effect of pore pressure depletion

  • Refracturing

  • Design and evaluation of refrac treatments
  • Models for fluid diversion when using diverting agents.
  • Advanced algorithms to distribute fluid, proppant proppant transport efficiency (PTE) correlations developed from hundreds of CFD-DEM simulations
  • Efficient moving mesh fracture model enables fast simulation with less computation cells
  • Implicit coupling between proppant distribution and multiple fracture propagation calculation
  • Quantitatively calculate proppant and fluid distribution for any given carrier fluid (gel, slickwater) and proppant type (sand, ceramic), proppant size, cluster/perforation geometry and injection schedule
  • Competitive fracture growth and inter-fracture stress interference.

  • Hydraulic fracturing in naturally fracted rocks

  • Simulate the creation of complex fracture networks.
  • Simulate thousands of natural fractures and other planes of weakness.
  • Model intersection of hydraulic fractures and natural fractures as well as the failure of non-intersecting fractures.
  • Fast simulations (typically runs in a matter of minutes on a PC).
  • Captures complex interaction between hydraulic fracture and natural fractures in 3-D simulations
  • Effect of shear events (microseismic) on the propagation of hydraulic fracture.
  • Competitive fracture growth and implicit inter-fracture stress interference.
  • Fluid and proppant distribution in complex fracture networks.
  • Post-pumping (after shut-in) proppant transport simulations to determine final propped fracture length.
  • Choice of natural fracture shape, size, density, orientation and mechanical properties provides greater flexibility for inputting complex geological features.
  • Provides final propped fracture geometry in minutes, empowering the user to run complex sensitivity analyses for improving fracture design.

Areas of Expertise

  • Multi-stage hydraulic fracturing in horizonal wells

  • Interaction between fractures in parent-child wells
  • Zipper-fracturing, re-fracturing & infill-well fracturing
  • Analyze inter-well and inter-stage fracture interference effects
  • 2-D and 3-D fracture propagation
  • Fracture turning
  • Prediction of number of active clusters per stage
  • Implicit fracture-reservoir model coupling.

 

 

  • Sand Management

  • Choke Management

  • Investigate sanding mechanisms in the field.
  • Design of well completions.
  • Optimal flowback strategies.
  • Model available to model both mechanical failure (shear/tensile/compressive failure) and fluid erosion.
  • Dynamic cell removal method allows us to accurately represent the dynamic process of sand removal from the wellbore/perforation face.
  • Our method also provides the possibility of studying the effect of arch stability on sanding.
  • Both single phase fluid flow (incompressible, slightly compressible, compressible fluid) and multi-phase fluid flow.
  • Explicit well geometries can be modeled, including vertical wells, horizontal wells, and deviated wells.
  • Sand production based on different well completions can be estimated.
  • Check the onset of sanding and the severity of sand production in both open-hole and cased & perforated wells.
  • Estimates of cumulative sand production vs. well/perforation pressure
  • Stress and pore pressure profiles
  • Well/perforation cavity shape during sand production

  • Hydraulic fracturing in unconsolidated sands (Frack-&-Pack)

  • Fracture propagation in elasto-plastic materials
  • Fracture pressure distribution inside the fracture
  • Proppant distribution inside the fracture
  • Displacement distribution in the porous reservoir
  • Stress distribution in the porous reservoir
  • Shear and tensile failure maps in the reservoir
  • Time vs fracturing pressure (net pressure) plot
  • Time vs fracture geometry (Height/Width/Length) plot
  • Pressure drop inside the fracture along fracture length

  • Injection well performance

  • Produced water reinjection
  • Injectivity
  • Fracture growth in injectors
  • Fracture containment
  • Flow distribution in multiple layers with fracture growth
  • Performance prediction of horizontal injectors
  • Water quality requirements
  • Wells/facilities design for deep water wells
  • Gravel-packed/Cased-perfed/Frac-packed wells
  • Fracture growth in 2D or 3D
  • Injection of water containing solid particles or oil droplets
  • Simulation of core flow tests
  • Thermally or hydraulically fractured wells