Designing an underbalanced drilling operation

A basic four-step process can be applied to determine the options and requirements for drilling underbalanced:

1. Determine bottom hole pressure (BHP) requirements
2. Identify the drilling fluid options
3. Establish the well design and perform flowing modeling
4. Select the surface equipment.

This article discusses the first two steps.

Bottom hole pressure (BHP) requirements

In overbalanced drillng (OBD), a mud weight is selected that provides a hydrostatic pressure of 200 to 1,000 psi above the reservoir pressure. In UBD, we select a fluid that provides a hydrostatic pressure of around 200 psi below the initial reservoir pressure. This provides a good starting point for the selection of a fluid system. During the feasibility study, this drawdown is normally further refined, depending on the expected reservoir inflow and other drilling parameters. This first look provides an indication if the fluid should be foam or gasified or if the well is drilling with a single-phase fluid (Fig. 1).

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  Fig. 1—BHP requirements

Drilling fluid systems

Correct selection of the fluid system used in UBD is the key to a successful UBD operation (Fig. 2). Initial fluid selection for UBD operations is classified into five fluid types based primarily on equivalent circulating density:

• Gas
• Mist
• Foam
• Gasified liquid
• Liquid

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  Fig. 2—UBD fluid density range.

Final fluid selection for UBD operations can be extremely complex. Key issues must be considered before a fluid design is finalized, such as:

• Reservoir characteristics
• Geophysical characteristics
• Well-fluid characteristics
• Well geometry
• Compatibility
• Hole cleaning
• Temperature stability
• Corrosion
• Data transmission
• Surface fluid handling and separation
• Formation lithology
• Health and safety
• Environmental impact
• Fluid source availability
• Staying below the reservoir pressure at all times, the primary objective for drilling underbalanced.

Gaseous fluids

Gaseous fluids are, basically, gas systems. In initial UBD operations, air was used for drilling. 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, because the combination of oxygen and natural gas may cause an explosive mixture. There have been a number of reported cases in which downhole fires have destroyed drillstrings, with the obvious potential consequences of the rig burning down if the mixture gets to surface.

Often, nitrogen is used if hydrocarbon reservoirs are drilled with a gas. For remote or offshore locations, a nitrogen generation system can be used to reduce the logistics. Another option might be the use of 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 produce sufficient gas at the right pressure to drill.

Gas drilling has advantages and disadvantages.

Advantages

• Fast penetration rates.
• Longer bit life.
• Greater footage per bit.
• Good cement jobs.
• Better production.
• Minimal water influx required.

Disadvantages

• Possibility of slugging.
• Possibility of mud rings in the presence of fluid ingress.
• Relies on annular velocity to remove cuttings from the well.

Mist systems

If a formation starts to produce small amounts of water when drilling with a gas system, the system is often changed to a mist system. The fluid added to the gas environment disperses into fine droplets, and forms a mist system that may be used for drilling. In general, this technique must be used in areas where some formation water exists, which prevents the use of complete “dry air” drilling. Mist drilling is similar to gas drilling, but with the addition of liquid, and has the following characteristics:

• It relies on annular velocity to remove cuttings from the well.
• It reduces formation of mud rings.
• It requires high volumes (30 to 40% more than dry gas drilling).
• Its pressures are generally higher than dry gas drilling.
• Incorrect gas/liquid ratio leads to slugging with attendant pressure increase.

Foam systems

Drilling with stable foam has some appeal, because foam has some attractive qualities and properties at the very low hydrostatic densities that can be generated with foam systems. Foam has good rheology and excellent cuttings-transport properties. Stable foam has some natural inherent viscosity, as well as fluid-loss-control properties, making it a very attractive drilling medium.

During foam drilling, the volumes of liquid and gas injected into the well are carefully controlled. This ensures that foam forms when the liquid enters the gas stream at the surface. The drilling fluid remains foam throughout its circulation path down the drillstring, up the annulus, and out of the well. The more stable nature of foam also results in a much more continuous downhole pressure condition because of slower fluid and gas separation when the injection is stopped.

Adding surfactant to a fluid and mixing the fluid system with a gas generates stable foam. 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 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 earlier foam systems, the amount of defoamer had to be tested carefully, so that the foam was broken down before any fluid entered the separators. In closed-circulation drilling systems, stable foam can cause particular problems with carry-over. The recently developed stable foam systems are simpler to break, and the liquid can also be refoamed so that less foaming agent is required, and a closed circulation system can be used. These systems, in general, rely on either a chemical method of breaking and making the foam, or the use of an increase and decrease of pH to make and break the foam.

The foam quality at surface used for drilling is normally between 80 and 95%. This means that of the total foam, 80 to 95% of the volume is gas, with the remainder being liquid. Downhole, because of the increased hydrostatic pressure of the annular column, this ratio changes because the volume of gas is reduced. An average acceptable bottomhole foam quality (FQ) is in the region of 50 to 60%.

Characteristics of foam drilling

• Extra fluid in the system reduces the influence of formation water.
• It has a very high carrying capacity.
• There are reduced pump rates because of improved cuttings transport.
• Stable foam reduces slugging tendencies of the wellbore.
• The stable foam can withstand limited circulation stoppages without affecting the cuttings removal or equivalent circulating density (ECD) to any significant degree.
• It has improved surface control and more stable downhole environment.
• The breaking down of the foam at surface must be addressed at the design stage.
• More increased surface equipment is required.

Gasified systems

In a gasified liquid system, gas is injected into the liquid to reduce the density. There are a number of methods that can be used to gasify a liquid system. The use of gas and liquid as a circulation system in a well significantly complicates the hydraulics program. The ratio of gas and liquid must be carefully calculated to ensure that a stable circulation system is used. If too much gas is used, slugging will occur. If not enough gas is used, the required bottomhole pressure will be exceeded, and the well will become overbalanced.

Characteristics of gasified-fluid systems

• Extra fluid in the system will almost eliminate the influence of formation fluid unless incompatibilities occur.
• The fluid properties can easily be identified prior to commencing the operation.
• Generally, less gas is required.
• Slugging of the gas and fluid must be managed correctly.
• Increased surface equipment is required to store and clean the base fluid.
• Velocities, especially at surface, are lower, reducing wear and erosion both downhole and to the surface equipment.

Gas/liquid ratios

Fig. 3 shows fluid/gas ratios for gasified fluid systems. As we move through the various fluid systems, the amount of gas in the fluid decreases as the density of the fluid increases. This has a significant effect on the hydraulics calculations. Special hydraulics software is required to ensure that the BHP remains underbalanced when circulating.

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  Fig. 3—Range of gas/liquid ratios of gasified fluids.

Single-phase fluids

If possible, the first approach used should be a single-phase fluid system with a density low enough to provide an underbalanced condition. If water can be used, then this would be the first step to take. If water is too heavy, oil can be considered. In oil reservoirs, it is not unknown to use the reservoir crude for drilling. When drilling with a crude-oil system, the rig’s surface equipment must be reviewed to ensure that hydrocarbons can be handled safely with the provided rig fluid systems. On offshore rigs, a fully enclosed, vented, and nitrogen-blanketed pit system may have to be used to ensure that any gas released from the crude does not form a safety hazard.

Gas lift systems

If a fluid must be reduced in density, the use of an injection of gas into the fluid flow could be an option. This offers a choice not only of the gas used but also in the way the gas is used in the well.

Normally, natural gas or nitrogen is used as a lift gas, but both CO₂ and O₂ can also be utilized. However, gases containing oxygen are not recommended for two main reasons:

• With hydrocarbon influx, there is the danger of a downhole fire or explosion.
• The combination of oxygen and saline fluids with the high bottomhole temperatures can cause severe corrosion to tubulars used in the well and drillstring. A number of injection methods are available to reduce the hydrostatic pressure.

Injection methods

Drillpipe injection

Compressed gas is injected at the standpipe manifold, where it mixes with the drilling fluid. Fig. 4 shows a typical drillpipe gas-injection configuration in a well.

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  Fig. 4—Drillpipe gas injection.

Advantages

The main advantage of drillstring injection is that no special downhole equipment is required in the well. The use of reliable nonreturn valves is required to prevent flow up the drillpipe. The gas rates used when drilling with drillpipe injection systems are, normally, lower than with annular gas lift. Relatively low Bottom Hole Pressures (BHPs) can be achieved using this system.

Disadvantages

• The disadvantages of this system include the need to stop pumping and the bleeding of any remaining trapped pressure in the drillstring every time a connection is made. This can result in an increase in BHP. It may be difficult to obtain a stable system, and avoid pressure spikes at the reservoir when using drillpipe injection.

• The use of pulse-type measurement while drilling (MWD) tools is only possible with gasified fluids with up to 20% gas by volume. If higher gas volumes are used, the pulse system deployed on MWD transmission systems will no longer work. Specialist MWD tools, such as electromagnetic tools, may have to be used if high gas-injection rates are required.

• A further drawback for drillstring injection is the impregnation of the gas into any downhole rubber seal. Positive displacement motors (PDMs) are prone to failure when rubber components are impregnated with the injection gas, and then tripped back to surface.

• During trips, the rubber components swell as a result of the expanding gas not being able to diffuse out of the elastomer sufficiently or quickly. This effect (explosive decompression) not only destroys downhole motors but also affects other tools with rubber seals used downhole. Special rubber compounds have been developed, and the design of motors is changing, to allow for this expansion.

Developments

The majority of motor suppliers can now provide PDMs specifically designed for use in this kind of downhole environment. Operational procedures must be written to ensure that connections can be made safely when drilling with high-pressure gas inside the drillstring.

Annular injection

Annular injection through a concentric string is most commonly utilized offshore in the North Sea. In new wells, a liner is set inside the target formation. The liner is tied back to surface using a modified tubing hanger to suspend the tieback string.

Process

Gas is injected in the casing liner annulus to facilitate the drawdown required during the drilling operation. Fig. 5 shows typical annular gas-injection configuration in a well.

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  Fig. 5—Annular gas injection.

The tieback string is pulled prior to installation of the final completion. The alternative is for an older well to have a completion in place incorporating gas lift mandrel pockets. These can be set up to provide the correct Bottom Hole Pressures (BHPs) during the drilling operation. The drawback with this type of operation is that the size of the hole and tools required could be restricted by the minimum inner diameter (ID) of the completion. However, the main advantage of using an annulus to introduce gas into the system is that gas injection is continued during connections, thus creating a more stable BHP.

Advantages

Because the gas is injected through the annulus, only a single-phase fluid is pumped down the drillstring. The advantage is that conventional MWD tools operate in their preferred environment, which can reduce the operational cost of a project.

Complications

The drawbacks of this system are that a suitable casing-completion scheme must be available, and that the injection point must be low enough to obtain the required underbalanced conditions. There may also be some modifications required to the wellhead for the installation of the tieback string and the gas-injection system.

Parasite-string gas injection

The use of a small parasite string strapped to the outside of the casing for gas injection is used only in vertical wells. Fig. 6 shows typical parasite-string gas-injection configuration in a well. The For safety reasons, two 1- or 2-in. coiled-tubing strings are strapped to the casing string above the reservoir as the casing is run in. Gas is pumped down the parasite string, and injected onto the drilling annulus.

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  Fig. 6—Parasite string gas injection.

Complications

The installation of a production casing string, and the running of the two parasite strings makes this a complicated operation. Wellhead modifications may be required to provide surface connections to the parasite strings.

Operational restrictions

This system is normally restricted to vertical wells to avoid damage to the parasite strings. The principles of operation and the advantages of this system are identical to the concentric gas injection system.

Alternatives

If natural gas is used to lighten the drilling fluid, annular injection is the preferred method. The use of natural gas through the drillstring is not recommended, because gas is released on the drillfloor during connections.

Hydraulic calculations

Because a compressible system is used in UBD, the annulus is always a mixture of gas and liquids. To calculate the BHPs in a gas/liquid environment, multiphase hydraulics must be used. Multiphase flow is probably some of the most complex fluid engineering known in the drilling industry. Multiphase or compressible fluids change considerably with pressures and temperatures.

Flow regimes

To correctly predict friction factors and liquid holdup, the flow regime in the annulus must be known. In OBD operations, we only consider laminar or turbulent flow. In UBD, many more variations must be considered. The flow regime varies with the inclination of the well. A number of methods and correlations are known to predict flow regimes.

The number of variables—fluids (gas/liquid) density, viscosity, compressibility, cuttings density, cuttings shape (or roundness), fluid composition, etc. and their interaction makes multiphase flow calculations a tasking and difficult undertaking. Because these variables are calculated over every iteration element of the well model, it is understandable that this has to be done with a computer program. Most flow models actually combine the various gas/liquid phases into the two-phase structure, as shown in Fig. 7.

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  Fig. 7—Generating two phases from multiple components.

Once this has been achieved, the model is now dealing with the conventional two-phase system with a liquid phase and a gas phase. The solids are combined in the liquid phase because this allows conventional fluid and cuttings transport models to be used for cuttings transport.

Noteworthy book

Mitchell, R. F., & Miska, S. (Eds.). (2011). Fundamentals of Drilling Engineering. Richardson, TX: Society of Petroleum Engineers. SPEBookstore and WorldCat

See also

PEH:Underbalanced Drilling