Gasified fluid drilling refers to the use of compressed air (or other gases) injected into an incompressible drilling fluid that flows in the annulus. This is accomplished by two basic methods.
- Drill pipe injection method requires the injection of compressed gas into the incompressible drilling fluid flow as this fluid is injected into the inside of the drill string at the top of the well. This allows the mixture of the gas and incompressible drilling fluid to flow throughout the circulating system. A variation on the drill pipe injection method is the use of a drill string jet sub above the drill collar/drill pipe interface to allow the injected gas to gasify the annulus above the jet sub position in the drill string. This later technique minimizes the aerated flow friction losses inside of drill collars and through drill bit nozzles.
- Annulus injection method requires the use of parasite tubing installed on the backside of the casing. This allows the upper section of the annulus to be aerated directly from the bottom of the casing.
The basic advantage of gasified fluid drilling is the control of pressure in the annulus (via surface adjustments). Through calculations and trial and error adjustments in the field, the inflow of formation fluids into the well can be controlled with the pressure exerted on the bottom of the annulus by the mixture of gas and incompressible drilling fluid. The gas injected into the incompressible drilling fluid is usually air.
Another important application for gasified fluid drilling has been in lost circulation situations. When incompressible drilling fluids are being lost in the annulus to thief formations, gasified fluid drilling techniques have been used successfully to minimize or eliminate the problem. The bubbles created by gasifying the incompressible drilling fluid tend to fill in the fracture or pore openings in the bore hole wall. This flow obstruction effect often controls the loss of incompressible drilling fluid to the thief zones.
The basic planning steps for the drilling of a deep well with gasified drilling fluids are as follows:
- Determine the geometry of the borehole section or sections be drilled with gasified drilling fluids (i.e., open-hole diameters, the casing or liner inside diameters, and depths).
- Determine the geometry of the associated drill strings for the sections to be drilled with gasified drilling fluids (i.e., drill bit size and type, the drill collar size, drill pipe size, and maximum depth).
- Determine the type of rock formations to be drilled and estimate the anticipated drilling rate of penetration. Also, estimate the quantity and depth location of any formation water that might be encountered.
- Determine the elevation of the drilling site above sea level, the temperature of the air during the drilling operation, and the approximate geothermal temperature gradient.
- Establish the objective of the gasified drilling operation:
- To allow formation fluids to be produced as the formation is drilled.
- To control the loss of circulation problems.
- To reduce formation damage.
- Determine whether direct or reverse circulation techniques will be used to drill the various sections of the well.
- If underbalanced drilling is the objective, to determine the bottom hole pressure limit that must be maintained in order to allow minimal production of formation fluids into the wellbore.
- For either of the above objectives, determine the required approximate volumetric flow rate of incompressible fluid to be used in the gasified fluid drilling operation. This is usually the minimum volumetric flow rate required to clean the rock cuttings from the bottom of the well and transport the cuttings to the surface. In most gasified drilling operations, the incompressible fluid volumetric flow rate is held constant as drilling progresses through the open-hole interval (as the gas injection flow rate is increased).
- Determine the approximate volumetric flow rate of air (or other gas) to be injected with the flow of incompressible fluid into the top of the drill string (or into the annulus) as a function of drilling depth.
- Using the incompressible fluid and air volumetric flow rates to be injected into the well, determine the bottomhole pressure and the associated surface injection pressure as a function of drilling depth (over the openhole interval to be drilled).
- Select the contractor compressors that will provide the drilling operation with the appropriate air or gas volumetric flow rate needed to properly aerate the drilling fluid. Also, determine the maximum power required by the compressor(s) and the available maximum derated power from the prime movers.
- Determine the approximate volume of fuel required by the compressor(s) to drill the well.
The circulation system for ed drilling operation can be modeled by as a multiphase flow calculation problem. In these problems, the pressure and temperature of the gas is usually known at the exit to the system. In this case, the exit is at the end of the return flow line to the mud tank. At this exit, the pressure and temperature are the local atmospheric pressure and temperature at the drilling location.
The calculation procedures for gasified drilling circulation problems are to start at these known exit conditions and work (or upstream) through the system. In these calculations, the volumetric flow rates of both the incompressible fluid and the injected gas must be assumed or known. If compressors are used to provide compressed air, then the volumetric flow rate is the sum of the outputs of all the primary compressors.
Unlike the air and gas drilling calculations described in the subsection above, most gasified drilling fluid operations are designed on a basis of an incompressible drilling mud (or other liquid phase) circulation rate that can carry the anticipated rock bit generated cuttings to the surface.
For direct circulation, the geometry of the well and the physical properties of the drilling mud are used to determine the minimum volumetric flow rate for the incompressible drilling mud in the “Minimum Volumetric Flow Rate” subsection below. Once this drilling mud minimum flow rate is known, the gas phase volumetric flow rate to be injected into the well is selected (trial and error) to give the appropriate bottom-hole pressure or other drilling conditions.
The equations given in the “Bottom-hole Pressure” subsection below are used to determine the bottom-hole pressure. These equations are applied from the top of the well annulus to each constant cross-section section in sequence starting from the top well. This is a trial and error calculation of determining the pressure at the bottom of the constant cross-section section of the well annulus. The pressure found at the bottom of each constant crosssection section is used as the initial pressure for the next deeper constant cross-section section until the bottom-hole pressure at the bottom of the annulus is determined.
In this calculation, all major and minor flow losses should be considered. Working upstream, the pressure above the drill bit orifices (or nozzles) inside the drill bit is found using the equations in the “Drill Bit Orifices and Nozzle” subsection. The equations given in the Injection Pressure subsection are applied from the bottom of the inside of the drill string to each constant cross-section section in sequence starting from the pressure above the drill bit. The pressure found at the top of each constant cross-section section is used as the initial pressure for the pressure at the top of next constant cross-section section until the injection pressure at
the top of the inside of the drill string is found. These are trial and error calculations.
Gasified drilling (or multiphase flow) calculation models are complex and cumbersome to apply and obtain predictions for field operations. The methodology outline above has been used to predict bottom-hole and injection pressures with an accuracy of about 15% to 20%.