Underbalanced Drilling (UBD)
Active In SP
Joined: Feb 2011
19-02-2011, 12:57 PM
Lesson 10 Flow Mudcap Snub Closed systems.ppt (Size: 3.84 MB / Downloads: 208)
Underbalanced Drilling (UBD)
Lesson 10 Flow Drilling ,Mudcap ,Drilling Snub Drilling ,Closed Systems
Flow drilling refers to drilling operations in which the well is allowed to flow to surface while drilling.
All UBD operations are really flow drilling operations, but the term is usually applied to drilling with a single phase mud, and no gas is injected except by the formation.
Drilling Fluid Selection
Density is determined by:
• Maximum pressure ≤ to formation pressure.
• Minimum pressure dictated by wellbore stability.
Pressure limitations of diverter and BOP equipment.
Sizing Flare Line
Weymouth’s equation can be used to predict the pressure drop for a gas, in steady-state, adiabatic, flow along the pipe:…
Primary oil separation pit.
Secondary oil separation pit.
Skimmer system safety.
Drilling fluid pit.
Oil transfer tank.
Mechanical objectives during flow drilling are:
• To control the well.
• Minimize differential sticking problems.
• Minimize drilling fluids losses.
Maximum tolerable surfaces pressures should be established before drilling starts.
Utilized with uncontrollable loss of circulation during flowdrilling operations.
Higher pressures than can be safely handled with the rotating head or RBOP.
It is not strictly an underbalanced drilling technique.
Driller loads the annulus with a relatively high density high viscosity mud and closes the choke with surface pressure maintained.
Drilling is then continued “blind” by pumping a clear non-damaging fluid down the drillstring through the bit and into the thief zone.
o Sustained surface pressures in excess of 2,000 psi.
o Sour oil and gas production.
o Small diameter wellbores.
Joined: Apr 2012
14-08-2012, 10:03 AM
UBD.pdf (Size: 694.57 KB / Downloads: 67)
This document is intended to provide an overview of current underbalanced
drilling technology and is therefore by no means exhaustive. It should serve as a
guide to current technology, explaining how and why underbalanced drilling is
What is Underbalanced Drilling?
When the effective circulating downhole pressure of the drilling fluid - which is
equal to the hydrostatic pressure of the fluid column, plus pump pressure, plus
associated friction pressures - is less than the effective near bore formation pore
Conventionally, wells are drilled overbalanced, which provides the primary well
control mechanism. Imposed wellbore pressure arises from three different
1. Hydrostatic pressure of materials in the wellbore due to the density of
the fluid used (mud) and the density contribution of any drilled cuttings
2. Dynamic pressure from fluid movement due to circulating friction of the
fluid used and the relative fluid motion caused by surge/swab of the
3. Imposed pressure, with occurs due to the pipe being sealed at surface
resulting in an area with pressure differential (e.g., a rotating head or
stripper element) (confining or active).
Reduction of ECD in extended reach wells
The drilling of long horizontal or near horizontal sections creates more
and more friction pressure in the annulus. This friction pressure acts on
the bottom of the well and slowly increases the overpressure over the
formation interval. This results in a reduction of ROP and increases the
potential for losses. Underbalanced drilling provides an opportunity for a
reduction in annular friction losses by allowing the reservoir energy to
push fluids out of the hole.
Bottom hole pressure requirements
In overbalanced drilling a mudweight is selected that provides a hydrostatic
pressure of 200 to 1000 psi above the reservoir pressure. In underbalanced
drilling we select a fluid that provides a hydrostatic pressure of around 100-200
psi below the initial reservoir pressure. This provides a starting point for the
selection of a fluid system. In the feasibility study this was further refined,
depending on the expected reservoir inflow, with a drawdown of 200 psi. A
closer look at the drilling hydraulics may indicate that 200 psi drawdown is not
sufficient and the well will be overbalanced when circulating. In this case, the
circulation fluid may have to be further reviewed.
Gaseous & Compressible (two-phase) Fluids
Compressible fluid drilling is, in essence, a drilling technique in which the more
common circulating fluids water or mud, are injected with or replaced by highly
compressible gases. These gases perform most of the same functions as a drilling
fluid, i.e., cool the bit and clean the hole.
Applicability of compressible fluid drilling is limited to a specific set of litho
logical and pore pressure conditions. It is also where significant savings of rig
time and money can be achieved despite the need for additional equipment.
Compressible fluid drilling includes: drilling with air, mist, foam stiff/stable and
These are basically the gas systems. In initial underbalanced drilling operations,
air was used to drill. Today air drilling or dusting is still applied in hard rock
drilling and in the drilling of water wells. The use of air in hydrocarbon bearing
formations is not recommended as the combination of oxygen and natural gas
may cause an explosive mixture. There have been a number of reported cases
where downhole fires have destroyed drillstring with the obvious potential
consequences of the rig burning down if the mixture gets to surface.
To avoid the use of air, nitrogen was introduced. The experience with nitrogen
in well servicing operations made it a first choice for underbalanced drilling
operations. The use of so-called cryogenic nitrogen or tanks of liquid nitrogen
in drilling operations can be restricted. This depends on the logistical issues
involved due to the large amount of nitrogen required for a drilling operation.
Another option is to use natural gas, which, if available, has sometimes proved
a worthy alternative in drilling operations. If a gas reservoir is being drilled
underbalanced, a producing well or the export pipeline may well produce
sufficient gas at the right pressure to drill. This avoids the introduction of
oxygen into the well and, if available, may provide a cheap drilling system.
If more liquid and a surfactant is added to the fluid, stable foam is generated.
Stable foam used for drilling has a texture not unlike shaving foam. It is a
particularly good drilling fluid with a high carrying capacity and a low density.
One of the problems encountered with the conventional foam systems is that a
stable foam is as it sounds. The foam remains stable even when it returns to the
surface and this can cause problems on a rig if the foam cannot be broken
down fast enough. In the old foam systems, the amount of defoamer had to be
tested carefully so that the foam was broken down before any fluid left the
separators. In closed circulation drilling systems stable foam could cause
particular problems with carry over. The recently developed stable foam systems
are simpler to break and the liquid can also be re-foamed so that less foaming
agent is required and a closed circulation system can be used.