Underbalanced drilling requires downhole pressure management

Zhihua Wang, Rolv Rommetveit
RF-Rogaland Research
Stavanger, Norway

Aarnoud Bijleveld
Shell Research & Technical Services
Rijswijk, The Netherlands

Roberto Maglione
Agip S.p.A.
Milano, Italy

Didier Gazaniol
Elf Aquitaine S.A.
Pau, France

Controlling downhole-pressure fluctuations while drilling underbalanced reduces formation damage, avoids lost circulation, and minimizes differential sticking.

One of the primary methods used to drill underbalanced is gas injection. It decreases the density of the drilling fluid and creates a condition where the bottom hole pressure (BHP) is less than the formation pressure (Fig. 1 [43004 bytes]).

When the BHP is less than formation pressure, formation fluids are able to enter the well bore, and in effect become production fluids.

Gas is injected into the well either through the drillstring or into the well annulus using a parasite string (casing, tubing).

An underbalanced drilling (UBD) operation must be designed to achieve underbalanced conditions throughout the entire drilling and completion operation. If underbalance is not maintained, problems associated with well bore instability will occur.

This first of a two-part series describes the dynamic situations occurring within the well bore while drilling underbalanced. The concluding article covers the use of a UBD drilling simulator for the purpose of optimizing well bore hydraulics.

The results presented in this article are those of an on-going, joint-industry project at RF-Rogaland Research, supported by Norske Shell, Norsk Agip, and Elf Petroleum Norge.

Pressure fluctuations

Assuming all other conditions are held constant, pressure fluctuation is the single most important factor that affects downhole conditions.

If there is a steady-state flowing condition with no up or down movements of the drillstring, the controlling mechanisms that define the BHP environment are:

• Well bore geometry

• Types of drilling fluid and injection gas

• Drilling fluid pump rates and gas injection rates

• Surface control procedures

• Injection methods

• Rates of reservoir production.

A stable operating range must be maintained, and well bore pressures should not be overly sensitive to changes in gas injection, fluid rates, and reservoir-pressure drawdown.

Excessive wellhead pressures and accidental situations of overbalance must be avoided.

Unfortunately, operations like drillstring movement, periodic and inconsistent fluid injection rates, tripping, and pipe connections interrupt normal flow conditions (Fig. 2 [37494 bytes]), creating pressure fluctuations within the well bore.

Field example

Pressure data from Well 1-FR-1-SC in the Parana basin of Brazil illustrates the dynamic conditions which can develop during an underbalanced drilling (UBD) operation.

This vertical well was drilled with a conventional rig using jointed drill pipe.

Fig. 3 [30729 bytes] shows the rates of gas injection and mud for the interval 860-884 m (2,822-2,900 ft). Fig. 4 [25514 bytes] shows the equivalent circulating densities (ECD) corresponding to the same depth and time intervals of Fig. 3.

As Fig. 4 shows, the ECD (mud weight) never reached a steady state within the time required to drill one section of pipe. The highest ECD during this period was nearly 50% higher than the lowest ECD during the same period.

These pressure oscillations were caused by flow interruptions due to operational requirements. For the period shown, gas and liquid injections were stopped in order to make drill pipe connections (Fig. 3).

Fig. 5 [31404 bytes] shows a plot of BHP vs. time for an oil well that was drilled underbalanced.¹ During the normal drilling process, the BHP varied within a range of 400 kilopascal (kPa).

However, dramatic pressure drops and rises were imposed on the well bore by adding drill pipe to the drillstring.

After circulation was discontinued for these connections, there were pressure drops of approximately 1,500 kPa below the average BHP due to frictional losses (Fig. 5).

Upon recommencement of circulation, the bottom hole pressures rose as much as 2,100 kPa (305 psi) above the average BHP, primarily due to fluid acceleration.

Therefore, in order to maintain a 100% underbalanced condition, the minimum drawdown pressure would be 2,100 kPa.

Factors causing dynamic pressures

In order to analyze the possible factors that affect bottom hole pressures (BHP), it is necessary to identify the causes that lead to dynamic pressures in an underbalanced drilling (UBD) operation.

By doing so, it is possible to avoid pressure fluctuations.

The flowing BHP is expressed as:

pwf = ph + pf + pacc + pwh

In a UBD operation, the flow system is typically a multiphase flow of gas, liquid, and solids.

In the above equation, ph is the hydrostatic pressure and is a function of gas and liquid densities and the gas-void fraction.

Gas density has a strong dependency on pressure and temperature. The gas-void fraction depends on gas and liquid flow rates.

Pf is the frictional pressure-loss component, pacc is the fluid-acceleration pressure, and pwh is the wellhead back pressure. The wellhead back pressure is dependent on the surface control of the choke, gas and liquid rates, and surface-pipe network.

All four components are dynamic and depend on the state of the system and time. When a disturbance is introduced into the system, all four components change accordingly.

Depending on the design and the state of the system, a disturbance may be quickly stabilized, or conversely, may lead to instability.

In a UBD operation involving gas injection, the BHP is affected by the interaction of the flowing-system elements including the gas injection line (parasitic string or drillstring), well bore, and reservoir (Fig. 2).

Field examples have shown that well bore pressures are dynamic during a UBD operation. This is due to the nature of the nonlinear, two-phase flow systems and the various disturbances during an operation.

If this dynamic system is not designed and controlled properly (Fig. 2), the desired BHP will not be achieved.

The major factors are:

• Nonlinear, two-phase flow systems

• Drillstring connections

• Drilling and tripping operations

• Uniformity of the fluid column (gas and liquid consistency)

• Equipment failures

• Initial flash production.

Simultaneously, the reservoir pressure in the vicinity of the well bore changes with time due to the influx of producing fluids (production).

This implies that although the BHP may remain relatively steady for short periods of time, the drawdown will nevertheless change with time.

Connections

In jointed pipe drilling, drillstring connections have the greatest effect on pressure fluctuations and spikes, especially when gas is injected through the drillstring.1

During a connection, the injection of gas is discontinued along with the circulation of liquids. The BHP is then reduced because of the partial loss of frictional pressure within the well.

If the BHP could be measured during a connection, the BHP loss could be compensated for by increasing the wellhead pressure.

Pressure reductions result in increased oil and/or gas production. The amount of production depends on the type of well, the reservoir productivity, and the reservoir drawdown.

In horizontal wells with long exposed sections, the additional production may lead to difficulties in regaining circulation without causing an overbalanced condition.

During a connection, fluid separation occurs both in the drillstring and the well. Changes to the hydrostatic-pressure profiles occur because liquid slugs accumulate near the lower part of the drillstring and well.

When circulation is re-established, frictional pressure is exerted on the bottom hole, amplified by the fluid acceleration. The liquid slugs in the drillstring are then pumped into the well, thereby increasing the hydrostatic pressure.

Consequently, elevated bottom hole pressures are maintained for a short period of time resulting in pressure spikes.

Because fluid separation is a function of time, it is important to reduce the time it takes to make a connection in order to minimize fluid separation.

Float valves can be placed inside the drillstring for safety reasons as well as to reduce the fluid separation during connections.

However, there is a need for further studies concerning float emplacement.

Annular gas injections

When gas is injected through a parasitic string, the pressure spikes caused during a drillstring connection may become small or large, depending on the procedures used.

If the annulus is left open during a connection, the drop in BHP and cessation of pump pressure will lead to:

• Increased reservoir production

• Increased gas rates from the parasitic string into the well

• Elevated gas-liquid ratios in the upper part of the well.

If caution is not exercised, the gas energy in the injection line may quickly deplete.

During a connection, fluid separation will occur at the top of the well if the annulus is closed.

If the annulus is open, the hydrostatic pressure will not significantly increase because there will be additional production influx because of the static condition.

However, the profile of the hydrostatic pressure gradient at the top of the well may change because of the accumulation of liquid slugs.

When circulation is re-established, frictional pressures are exerted on the bottom hole, amplified by fluid acceleration.

If the gas energy is properly preserved during the connection, large pressure spikes may be avoided. Otherwise, a pressure spike will occur followed by a period of elevated bottom hole pressures.

Unlike drillstring gas injections, the BHP depends upon sustaining liquids in the upper part of the well, and the rates of gas injection.

The interaction between the well and gas injection is more important in this case.

Tripping

Underbalanced conditions are difficult to maintain while tripping.

However, the ability to circulate while tripping improves management of the underbalanced condition, especially when utilizing drillstring gas injection.

A coiled tubing unit provides the ability to circulate while tripping in and out of the hole.

However, caution must still be exercised when reconfiguring the bottom hole assembly, because during this time circulation is not possible.

When a conventional rig is used, circulation is normally unavailable while tripping.

If there is pressure on the well, the well should be killed by increasing the hydrostatic pressure before tripping. This will cause an overbalanced condition.

Even if it is necessary to snub the string under conditions of abnormal well pressures, the underbalanced condition may eventually discontinue due to reservoir pressure depletion.

When annular gas injection is used, a similar situation will occur unless the string is snubbed in and out under pressure.

However, if the string is snubbed out, an underbalanced condition can still be maintained because gas injection can continue while tripping.

Consequently, improper tripping procedures may negate the gain achieved before tripping, and caution should be exercised to minimize the development of dynamic pressures while tripping in and out of the hole.

If the well has to be killed by increasing the hydrostatic pressure, native fluids should be used in the reservoir section since they are the least damaging to the formation.

MWD surveying

Measurement while drilling (MWD) logging requires that the entire drillstring be filled with liquid, because current MWD tools use pulse-telemetry to transmit data to the surface through a liquid column.

Unfortunately, this creates a problem for drillstring gas injection because it introduces nonliquid voids into the well annulus.

After an MWD logging run is completed, and circulation and injection are reinitiated, large slugs of liquid from the drillstring are introduced into the well annulus, creating pressure spikes.

Fortunately, with increasing improvements in electromagnetic MWD, this problem may be resolved because these instrument types do not require a homogeneous liquid phase to transmit data.

When annular gas injection is used, a uniform column of liquid is available inside the drillstring and does not present any problems to logging.

Equipment failures

When there are equipment failures and/or interruptions of gas injection, the drilled portion of the hole may become exposed to an overbalanced condition either by hydrostatic pressure or through a shut-in situation.

Subsequent re-establishment of circulation will result in undesired BHP fluctuations.

Reservoir depletion

By conventional definition, pressure underbalance is defined as the difference between reservoir pressure and the flowing BHP.

When an underbalanced well has established production, reservoir pressure depletion may occur.

This is more significant in cases of low permeability reservoirs which have highly underbalanced pressures and limited drainage areas.

When this situation occurs, dynamic well-bore pressure fluctuations will cause fluid invasion even if the largest spike is within the range of nominal reservoir pressures.

To maintain the well in a state of underbalance at all times, localized reservoir pressure depletion will need to be taken into account. This implies that the BHP will decrease with time.

Design considerations

Two major factors affect well bore pressure changes. One is the nature of the nonlinear, two-phase flow system. The other comes from interruptions to the system.

Some of the interruptions are required for normal operations, but others are due to limitations of current technology and unforeseen situations.

It is possible to approach these problems through:

• Better understanding of the UBD physical process

• Training of rig personnel

• Operational procedures

• Preoperational planning

• Technology development.

References

1. Saponja, J., "Engineering Considerations for Jointed Pipe Underbalanced Drilling," paper presented at the First International Underbalanced Drilling Conference & Exhibition, The Hague, Netherlands, Oct. 2-4, 1995.

2. Rommetveit, R., Vefring, E.H., Wang, Z., Bieseman, T. and Faure, A.M., "A Dynamic Model for Underbalanced Drilling With Coiled Tubing," SPE paper No. 29363, presented at the 1995 IADC/SPE Drilling Conference, Amsterdam, Feb. 28-Mar. 2, 1995.

3. Wang, Z., Rommetveit, R., Vefring, E.H.., Bieseman, T. and Faure, A.M., "A Dynamic Underbalanced Drilling Simulator," paper presented at the 1st International Underbalanced Drilling Conference & Exhibition, The Hague, Oct. 2-4 1995.

4. Wang, Z., Vefring, E.H., Rommetveit, R., Bieseman, T., Maglione, R. and Lage, A.C., "Development and Verification of a Dynamic Underbalanced Drilling Simulator," paper presented at Energy Week '97 Conf. & Exhibition, Houston, Jan. 28-30, 1997.

Nonlinear, two-phase flow system

IF GAS IS INJECTED THROUGH either a drillstring or parasitic string (annular), there will be an interaction between the injection line, well bore, and reservoir.

Depending on the system geometry and design, this interaction may lead to unsteady:

• Gas injection rates

• Production from the formation

• Wellbore pressures.

This system is similar to a gas lift well for which there are thoroughly documented cases. Unfortunately, there is a lack of similar information for UBD operations.

Instead, a dynamic underbalanced drilling simulator can be used to simulate a through-completion, underbalanced-drilling operation.2-4

Table 1 [9424 bytes] and Table 2 [11558 bytes] list the necessary data for a simulation. The well profile is vertical to 994 m (3,261 ft), but reaches deviations of 8.5° by total depth.

Fig. 1 shows the bottom hole pressure (BHP) as a function of gas injection rates under steady-state conditions, with and without reservoir production.

For the dynamic simulation, it is assumed that the system is filled with a drilling fluid and that the bit is on bottom at a depth of 2,170 m (7,119 ft) measured depth.

The choke is set at a specific opening to simulate the surface-flow pipe resistance.

The simulation begins with mud pump rates of 150 l./min (40 gpm) and annular nitrogen injection rates (parasitic string) of 400 scfm. Both rates are maintained constant throughout the simulation.

Fig. 2 shows bottomhole, compressor, and wellhead pressures. Fig. 3 shows both the gas flow rate into the well from the parasitic string and the total gas-flow out rate.

Before the injection gas enters the well, the BHP and wellhead pressures are relatively stable, accompanied by a steadily increasing compressor pressure.

At time = 67 min, the injection gas suddenly enters the well. At the same time, both the BHP and compressor pressure begin to drop rapidly. In addition, the wellhead pressure begins to increase.

Drilling commences at 60 ft/hr at time = 76 min, when the BHP is lowered to reservoir pressure. During this period, no changes are made to any control parameters.

The energy in the gas injection line at this time depletes rapidly. The injection rate into the well peaks at time = 76 min, then drops sharply, falling to zero at time = 90 min.

The BHP begins to increase at time = 84.5 min. From time = 90 min, no gas is injected into the well, and the BHP increases rapidly due to fill-up of the top part of the well because of hydrostatic head. The gas injection line is repressured during this time period.

At time = 130 min, gas starts to enter the wellbore again, and a similar trend is observed as in the first cycle.

In order to avoid a kick-off problem, the wellhead pressure is increased to prevent the wellbore pressure from dropping too rapidly.

This is done by partially closing the choke at time = 136.5 min once the BHP has dropped to 50 bar (725 psi) from a plateau of 217 bar (3,147 psi). During this time the gas-flow out rate increases.

Although the wellhead pressure increased rapidly, the BHP continues to drop because the gas rates into the well are higher than the gas-flow out rates. At the same time, the gas rapidly expands as it approaches the surface.

This action stabilizes the system and the formation begins to produce again at time = 150 min. A few minutes later, the choke is opened gradually back to the original setting.

The system stabilizes and approaches a steady state.

This example demonstrates how the system interacts among the various flowing units. An understanding of both the physical process and how to control the well bore pressure regimes leads to better management of wellbore pressure fluctuations.

The Authors