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Underbalanced drilling circulation designs
In designing a UBD circulation system, the bottomhole pressure must be maintained below the reservoir pressure. The surface separation system must have sufficient capacity to handle the flow rates and pressures expected while drilling.
Factors to consider in an UBD circulation system design
The surface separation system must be capable of handling sudden productivity increases from the well from fractures or flush zones and retain the ability to “choke” back production if well outflow is more than what can be handled safely by the surface separation equipment. The separation system must also be able to work within the design parameters of the well. The design of a UBD circulation system must consider certain factors:
- Bottomhole pressure (BHP)
- Reservoir inflow performance and control
- Cuttings transport and hole cleaning
- Motor performance in multiphase-flow environment
- Surface equipment capabilities and limitations
- Environment considerations
- Wellbore stability
Bottomhole pressure (BHP)
The BHP must be less than the static reservoir pressure under static and dynamic conditions to enable reservoir fluid inflow into the wellbore. This difference creates the driving force that drives well productivity.
Reservoir inflow performance and control
The productivity of the reservoir while drilling underbalanced is a function of BHP and several reservoir characteristics like:
- Length of reservoir exposed to the wellbore
- Drainage radius
- Pressure driving force
The pressure driving force (reservoir pressure—well BHP) is the most important in controlling reservoir inflow because most of the parameters are relatively fixed by the geology. Therefore, the BHP must be controlled by either hydrostatic drilling fluid or by the choke to control reservoir inflow performance.
Cuttings transport and hole cleaning
Cuttings generated while drilling underbalanced must be removed from the wellbore by the hydraulic action of the drilling fluid. For hole cleaning to be effective, the fluid annular velocity has to be at least twice the cuttings’ settling velocity.
Motor performance in multiphase-flow environment
While drilling with multiphase fluids, it is important that the motor performance is not compromised by the hydraulics. The equivalent flow rate through the motor should be sufficient to deliver the required performance and be within the motor operating envelope.
Surface equipment capabilities and limitations
The productivity of the reservoir while drilling and the length of reservoir that should be exposed to the wellbore is constrained by the capacity of the surface separation facility. UBD safety systems are designed so that the surface system shuts down automatically if the rate from the well exceeds its capacity. Surface equipment capacity must always be designed to handle the maximum expected production from the well, whether instantaneous or steady-state.
Because of governmental legislation and/or operators’ policies, UBD operations may have to be carried out with zero emissions to the environment—that is, no gas flaring. Where this is the case, the surface separation system has to be designed for total containment of the produced cuttings and reservoir fluids inflow—oil, gas, and water. Otherwise, gas re-injection will need to be considered. Gas re-injection requires a gas recompression plant so that gas can be re-injected at the right pressure.
Exposing wellbore to pressure drawdown imposes stresses on the surrounding formation. If the stresses exceed the strength of the formation, hole collapse could occur. It is, therefore, important that a thorough borehole stability study be conducted to evaluate the feasibility of a reservoir as a candidate for UBD.
The graph in Fig. 1 gives the first operating envelope for UBD. The operating envelope is bound by a number of curves.
The annular bottomhole pressure graph is a combination chart of hydrostatic pressure vs. gas injection rate. As gas is injected into a fluid system, the hydrostatic pressure drops as more and more gas enters the system. As the amount of gas in the system increases, it is compressed at the bottom of the well, and expands as it rises to the surface of the well. The hydrostatic pressure drops as we inject more gas, but the friction pressure starts to increase as more gas enters the well and expands on its way back to the surface(see Fig. 2).
If we combine these two effects into a single curve, we get the typical pressure vs. gas rate curve, as shown in Fig. 3. The brown curve now shows the combined curve of hydrostatic pressure and friction pressure. In the first part of the curve, we see the rapid decline of pressure as we increase the amount of gas. This part of the curve is known as the hydrostatically dominated part of the design curve. As the amount of gas increases, the friction pressure in the well also increases as a result of the gas expansion. The flatter part of the pressure curve is known as the friction-dominated part of the curve.
As the gas-injection rate increases further, the BHP starts to increase as a result of the friction pressure.
To design a circulation system that provides stable BHPs, the system should avoid pressure spikes as well as slugging. The operating envelope allows the drilling engineer to determine, for a particular gas-injection rate, whether the flow is dominated by hydrostatic or frictional pressure loss. Any point on the performance curve with a negative slope is dominated by hydrostatic pressure losses. These points are inherently unstable, show large pressure changes with small changes in gas flow rate, and exhibit increasing BHP with decreasing gas flow rate. Operating on the hydrostatic-dominated slope means that severe slugging is encountered while drilling.
Points on the performance curve with a positive slope are dominated by frictional pressure loss. These points are inherently stable and exhibit increasing BHP with increasing gas flow rate.
It is important to note that “dominated by frictional pressure loss” does not necessarily imply that the frictional pressure loss is greater than the hydrostatic pressure loss. Instead, this means that the reduction in hydrostatic pressure associated with an increase in the gas-injection rate is less than the increase in frictional pressure because of the increased gas flow rate.
This information can be used in several ways. If a reduction in bottomhole pressure is required, a decrease in gas injection, the obvious answer to someone only familiar with single-phase flow, will lead to an increase in bottomhole flowing pressure, if the flow is hydrostatic-dominated. Further, the cost of nitrogen (as the injection gas), if bulk liquid nitrogen is used, can be one of the most significant costs associated with UBD operations.
One of the most common misconceptions in UBD is that more nitrogen (i.e., gas) injection is better. This stems from observations of drilling operations that are hydrostatic-dominated, in which an increase in the gas-injection rate can lead to significant decreases in the bottomhole pressure. However, if the drilling operation is frictionally dominated, increasing the gas-injection rate will not only increase the bottomhole pressure but may dramatically increase the cost associated with nitrogen used while drilling. Saponja recommended that UBD is carried out in the friction dominated part of the pressure curve. Operations conducted on the hydrostatic part of the curve often report that a cyclic bottomhole pressure occurs, and that it is difficult to obtain a stable system. More gas is the answer here to move onto the friction-dominated part of the design curve.
Thus, for a specific design case, the operating envelope not only can confirm the feasibility of UBD but also offers valuable insights into both the acceptable and optimal gas injection rates and the influence of those rates on the bottomhole flowing pressure. Operating envelopes should be developed for a range of design parameters.
The operating envelope cannot tell the entire story, however. Each point on the operating envelope corresponds to a single wellbore calculation for a specific gas-injection rate. For all such calculations, valuable additional information can be gathered by analyzing:
- Profiles of the in-situ liquid holdup
- Actual gas and liquid velocities
At the moment, we are only concerned with the BHP. At a given flow rate, we calculate the BHP in the well for a certain fluid system, well configuration, drillstring, and surface pressure.
As we construct this first graph (Fig. 4), several other issues must be considered. The first issue is the reservoir pressure. We must establish if we can achieve a certain target pressure below the reservoir pressure. A target pressure is normally established at some 250 psi below the known reservoir pressure. Fig. 5 shows liquid-flow rate and gas-injection rate vs. BHP. We now see a system that is able to achieve an underbalanced status below the reservoir pressure. We have a friction-dominated part of the design curve below the reservoir pressure, and have the first operating parameters for our flow model. This curve is normally created with three or four different flow rates. Note that the shaded area is the margin between the target pressure and the predicted pressure. Fig. 6 shows the margin between target pressure and actual pressure. Once we have a number of fluid rates, we continue to define the next set of operating parameters, and we further define the operating window.
The next set of curves that we introduce (Fig. 7) in this curve is the minimum and maximum flow rate through the downhole motor. We now have a minimum motor speed that we need to drive the bit. We also have a maximum flow rate that the motor can handle without being damaged. Note that the motor limit line is slanted because the total flow rate is different for each curve at given gas rate.
It is also important to note that the maximum motor flow rate may be higher than the maximum gas-injection rate on the graph. It is not always possible to have the motor limits on the same graph.
The last information on this curve is the minimum liquid velocity for hole cleaning. Again it is sometimes impossible to show this on the design graph because the annular velocity maybe high enough without the gas injection.
- Saponja, J. 1995. Underbalanced Drilling Engineering and Well Planning. Presented at the International Underbalanced Drilling Conference and Exhibition, The Hague, The Netherlands, 2-4 October.