Oil and Gas Well Projects

My main expertise is in the development of numerical models and implementation of engineering software for well cementing – the process in the construction of a wellbore whereby cement is placed between the casing and the formation. The primary objective of well cementing is to achieve zonal isolation so that the fluids from one formation zone (such as oil or gas) do not migrate to another zone or the surface. Failure to achieve it may lead to many serious problems: gas or oil can flow to the surface causing a blowout, with consequent environmental damage and a possible loss of life. Reservoir fluids may migrate into a subsurface aquifer causing contamination of drinking water, or affecting near-wellbore ecology. Finally, reservoir pressure can be significantly decreased resulting in the loss of productivity.

Whilst the majority of our projects dealt with the primary cementing, they have significant application and commonality with remedial cementing, fracturing and drilling. The fluids and equipment used, well description and risk factors are in many instances common with models that can be readily shared or adopted for these other uses.

  • Placement Job Design. An important part of the job design for primary and remedial cementing is computing fluid volumes for fluids to be pumped during the job. Fluid compressibility, effect of temperature and valve placement are considered when computing these volumes. For plug cementing jobs where the casing is withdrawn from the well after the cement is placed, a hydrostatic balancing calculation is required to ensure level fluid interfaces at the end of the pull out to avoid contamination of cement with other fluids. 
  • Dynamic Hydraulic Simulation. Simulation of displacement flow of multiple compressible fluids in the well as part of the cementing process. Given the pumping schedule of fluids with volumes and flow rates defined, compute the flow rates and pressures throughout the well to the end of the job. The primary goal of the calculations is to establish dynamic well security – that is the pressure in the well is above the formation pore pressure and below the fracture pressure. Additionally, risk factors such as casing burst/collapse, volume of losses to formation and well security in cases of loss of well control are computed. The fluid positions at the end of placement can be also compared with the design goals. 
  • Foam Placements. In some cases, a gas (typically nitrogen) is injected into the cement slurry as it is being pumped into the well primarily to reduce the effective density of the cement and thus to reduce pressure in the well during cement placement. As the volumetric ratios of gas to liquid as high as 250 at atmospheric conditions such foams are highly energetic - they expand in volume by many times with pressure variations. This in turn can lead to drastic variations in flow velocities making fluid positions hard to predict and even compromising well security if the placement is not controlled. We have experience of implementing static and dynamic simulations of foam job design and placement to assess well security, ensure final interface positions and calculate maximum foam quality (ratio of gas to foam) not to exceed a maximum beyond which the foam. 
  • Temperature Simulation. Temperature in the well can vary by several hundred degrees between the surface and bottomhole conditions. This can significantly affect the density and rheology of the drilling and cementing fluids. Because of this, simulation of temperature both inside the fluids during their placement and in the formation is crucial to the accurate fluid placement simulations. We have experience of modelling and implementation of such temperature simulations, coupling the results to other temperature-dependent static and dynamic fluid simulators. 
  • Fluid Interface Stability. As the sequence of fluids are pumped into the well and travel down the pipe or through the annular gap, the interface between each pair of fluids shifts. Dispersion, mixing and diffusion effects and lead to significant zones of mixed fluids or fluid channels at the end of placement. After hydration, these areas can remain permeable to the gas migration and can pose a significant risk if not quantified. We have experience of modelling displacement flow of non-Newtonian fluids in pipe and annulus to simulate the interface evolution – and to ascertain the effect of centralizers and mechanical separators on improving quality of placement. 
  • Non-Newtonian Fluids. Many fluids used in cementing, drilling and production are non-Newtonian – that is they exhibit a non-constant viscosity and a non-zero shear stress at low shear rates. Typically, these are characterized with a Herschel-Bulkley rheology model which can in turn vary significantly with pressure and temperature. We have experience in implementing a variety of pressure and temperature variable rheological models based on experimental readings or fluid composition and using these models in dynamic fluid simulations. 
  • Cement Sheath Stress Analysis. After placement and setting of the cement, the well can be subjected to temperature and pressure variations – for example during its production life, further cementing operations or well stimulation. These variations can place significant mechanical stresses on the cement sheath and can potentially lead to material failure – through traction, compression or a formation of a gap. This in turn leads to loss of zonal isolation. We have experience of modelling and implementing simulations computing material stresses in multi-casing cement wells due to pressure and temperature variations to assess the risk of mechanical failure or gap formation.