Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume II - Drilling Engineering
Robert F. Mitchell, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 12 - Underbalanced Drilling
What is Underbalanced Drilling?
In underbalanced drilling (UBD), the hydrostatic head of the drilling fluid is intentionally designed to be lower than the pressure of the formations that are being drilled. The hydrostatic head of the fluid may naturally be less than the formation pressure, or it can be induced by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether the underbalanced status is induced or natural, the result may be an influx of formation fluids that must be circulated from the well and controlled at surface.
The effective downhole circulating pressure of the drilling fluid is equal to the hydrostatic pressure of the fluid column, plus associated friction pressures, plus any pressure applied on surface.
Conventionally, wells are drilled overbalanced. In these wells, a column of fluid of a certain density in the hole provides the primary well-control mechanism. The pressure on the bottom of the well will always be designed to be higher than the pressure in the formation (Fig. 12.1a).
In underbalanced drilled wells, a lighter fluid replaces the fluid column, and the pressure on the bottom of the well is designed intentionally to be lower than the pressure in the formation (Fig. 12.1b).
Because the fluid no longer acts as the primary well-control mechanism, the primary well control in UBD arises from three different mechanisms:
- Hydrostatic pressure (passive) of materials in the wellbore because of the density of the fluid used (mud) and the density contribution of any drilled cuttings.
- Friction pressure (dynamic) from fluid movement because of circulating friction of the fluid used.
- Choke pressure (confining or active), which arises because of the pipe being sealed at surface, resulting in a positive pressure at surface.
Flow from any porous and permeable zones is likely to result when drilling underbalanced. This inflow of formation fluids must be controlled and any hydrocarbon fluids must be handled safely at surface.
The lower hydrostatic head avoids the buildup of filter cake on the formation as well as the invasion of mud and drilling solids into the formation. This helps to improve productivity of the well and reduce related drilling problems.
UBD produces an influx of formation fluids that must be controlled to avoid well-control problems. This is one of the main differences from conventional drilling. In conventional drilling, pressure control is the main well control principle, while in UBD, flow control is the main well-control principle. In UBD, the fluids from the well are returned to a closed system at surface to control the well. With the well flowing, the blowout preventer (BOP) system is kept closed while drilling, whereas in conventional overbalanced operations, drilling fluids are returned to an open system with the BOPs open to atmosphere (Fig. 12.2). Secondary well control is still provided by the BOPs, as is the case with conventional drilling operations.
Lowhead drilling is drilling with the hydrostatic head of the drilling fluid reduced to a pressure marginally higher than the pressure of the formations being drilled. The hydrostatic head of the fluid is maintained above the formation pressure, and reservoir inflow is avoided. Lowhead drilling may be undertaken in formations that would produce H 2 S or would cause other issues if hydrocarbons were produced to surface.
Why Drill Underbalanced
The reasons for UBD can be broken down into two main categories:
- Maximizing hydrocarbon recovery.
- Minimizing pressure-related drilling problems.
There are also specific advantages and disadvantages of performing a drilling operation underbalanced. These are summarized in Table 12.1.
Maximizing Hydrocarbon Recovery. There is no invasion of solids or mud filtrate into the reservoir formation. This often eliminates the requirement for any well cleanup after drilling is completed.
Early. Production. The well is producing as soon as the reservoir is penetrated with a bit. This could also be a disadvantage if hydrocarbon production cannot be handled or stored on site, or if the required export lines are not available.
Reduced Stimulation. Because there is no filtrate or solids invasion in an underbalanced drilled reservoir, the need for reservoir stimulation, such as acid washing or massive hydraulic fracture stimulation, is eliminated.
Enhanced Recovery. Because of the increased productivity of an underbalanced drilled well combined with the ability to drill infill wells in depleted fields, the recovery of bypassed hydrocarbons is possible. This can significantly extend the life of a field. The improved productivity of the wells also leads to a lower drawdown, which, in turn, can reduce water coning.
Increased Reservoir Knowledge. During an underbalanced drilling operation, reservoir productivity and the produced fluids can be measured and analyzed while drilling. This allows a well to be drilled longer or shorter, depending on production requirements. An operator is also able to determine the most productive zones in a reservoir in real time and obtain well test results while drilling.
Skin factors on most underbalanced drilled wells are negative, just as they are in wells drilled and stimulated.
Minimizing Pressure-Related Drilling Problems. Differential Sticking. The absence of an overburden on the formation combined with the lack of any filter cake serves to prevent the drillstring from becoming differentially stuck. This is especially useful when drilling with coiled tubing because coiled tubing lacks tool joint connections that increase the standoff in the borehole and then helps minimize sticking of conventional drillpipe.
No Losses. In general, a reduction of the hydrostatic pressure in the annulus reduces the fluid losses into a reservoir formation. In UBD, the hydrostatic pressure is reduced to a level at which losses do not occur. This is especially important in the protection of fractures in a reservoir.
Improved Penetration Rate. The lowering of the wellbore pressure relative to the formation pressure has a significant effect on penetration rate. The reduction in the "chip holddown effect" also has a positive impact on bit life. The increased penetration rate combined with the effective cuttings removal from the face of the bit leads to a significant increase in bit life. In underbalanced drilled wells, sections have been drilled with only one bit where an overbalanced drilled well might need three, four, or even as many as five bits. It is normally assumed that penetration rates double when drilling underbalanced.
Classification System for Underbalanced DrillingA classification system developed by the Intl. Assn. of Drilling Contractors (IADC) is helping to establish the risks associated with underbalanced drilled wells (Table 12.2).
The matrix given easily classifies the majority of known underbalanced applications. This system combines the risk management categories (Levels 0 to 5) with a subclassifier to indicate either "underbalanced" or "low head" drilling using underbalanced technology. To provide a complete method of classifying the type of technology used for one or more sections of a well, or multiple wells in a particular project, a third component of the classification system addresses the underbalanced technique used, as shown in Table 12.3.
Example of Classification System Use. A horizontal section of a well is drilled in a known geologic area using a drilling fluid lightened with nitrogen gas to achieve an underbalanced condition through the reservoir section. The maximum predicted bottomhole pressure (BHP) is 3,000 psi with a potential surface shut-in pressure of 2,500 psi. This is classified as a 4-B-4 well indicating classification level 4 risk and UBD drilling with a gasified liquid. All wells classified as a Level 4 or Level 5 underbalanced well require significant planning to ensure safe underbalanced drilling.
Selecting the Right Candidate for UBDMost reservoirs can be drilled underbalanced. Some reservoirs cannot be drilled underbalanced because of geological issues associated with rock stability. For some reservoirs, it might not be possible to drill underbalanced with the current technology because they are either prolific producers or pressures are so high that safety and environmental concerns prevent safe underbalanced drilling. These may include high-pressure or sour wells (although both types have been drilled underbalanced, but with significant engineering considerations and planning).
Candidate selection for UBD must focus not only on the benefits of UBD but also on additional considerations. It is important that the right reservoir is selected for a UBD operation. Table 12.4 shows reservoir types that will and will not benefit from UBD. Of course, not only the reservoir has to be evaluated, but also the well design and the possible damage mechanisms and the economic reasons for UBD. All issues must be considered carefully when choosing whether or not to drill underbalanced.
Reservoir Selection IssuesAppropriate reservoir screening is essential for the correct selection of a suitable reservoir application for vertical or horizontal UBD. A systematic approach, outlined in the following section, identifies the major areas of study to ascertain if sufficient information is available to initiate the design work for a viable UBD process.
Once this information is gathered and reviewed and if data show that an UBD operation is the best method for recovering hydrocarbons in an economically and technically successful manner, it is time to mobilize the team to design and execute the UBD operation. Steps in a typical UBD evaluation process are outlined in Table 12.5. Fig. 12.3 shows this UBD evaluation process as a flow chart.
It is important not to forget the business driver behind the technology. If benefits cannot be achieved, the project must be reviewed. The improvements from UBD—increased penetration rate, increased production rate, and minimization of impairment—must offset the additional cost of undertaking a UBD project.
This is often the most difficult limitation of UBD to overcome. If the reservoir/production engineers are not convinced that there is a sound reason for drilling underbalanced for productivity reasons, most underbalanced projects will never get past the feasibility stage.
To drill a well underbalanced, extra equipment and people are required, and this adds to the drilling cost of a well. The operators must show a return for their shareholders, so they will want to know if this extra investment is worthwhile before embarking on a UBD project.
Costs Associated With Underbalanced Drilling
The following factors contribute to the cost increases for an underbalanced drilled well in comparison to a conventionally drilled well:
- Pre-engineering studies.
- Rotating diverter system.
- Surface separation and well-control package.
- Snubbing system to deal with pipe light.
- Data acquisition system.
- Extra downhole equipment[
nonreturn valves and pressure while drilling (PWD) ] .
- Special drillstring connections (high-torque gas that is tight with special hardbanding).
- Additional personnel training.
- Additional operational wellsite personnel.
- Additional safety case update consistent with planned UBD operations.
- Extra time required to drill underbalanced.
From industry experience to date, we can state that underbalanced drilled wells are 20 to 30% more expensive than overbalanced drilled wells. This applies to both offshore and onshore operations in a similar area.
Cost alone is, however, not a good measure for the evaluation of UBD. The value of the well must also be recognized. The average three-fold increase in productivity of an underbalanced drilled well can add considerable value to a field development plan or a field rehabilitation program. If we add a potential increased recovery from a field to the value of an underbalanced well, even an increase as small as 1% in total hydrocarbon recovery may have a large impact on field economics.
Prior to a UBD operation, some reservoir engineering work should be carried out. Not only is an accurate reservoir pressure needed, but the damage mechanism of the reservoir must be understood to ensure that the benefits of UBD can indeed be obtained. Some wells or reservoirs are suitable for underbalanced operations and result in an enhanced recovery. Other formations or fields may not be viable for a variety of reasons. If formation damage is the main driver for UBD, it is important that the reservoir and petroleum engineers understand the damage mechanisms resulting from OBD. We must remember that even underbalanced drilled wells can cause formation damage.
Coreflush testing may be required to establish compatibility between the proposed drilling fluid and the produced reservoir fluids. This is critical if oil reservoirs are to be drilled underbalanced. The potential for scale and emulsion forming must also be reviewed prior to starting operations. We must ascertain the stability of the zone of interest to determine if the proposed well path is structurally capable of being drilled with the anticipated formation drawdown.
Expected productivity with the proposed drawdown must be reviewed. The objective of UBD is to clean the reservoir and not to produce the well to its maximum capacity. If the reservoir is likely to produce any water, we must take this into account because water influx can have significant effects on the underbalanced process. It is important that expected productivity be analyzed with the reservoir engineers to obtain an accurate indicator as to whether UBD would be beneficial.
Once reservoir issues are fully understood, advantages to drilling underbalanced are proven, and the proposed well profile can be achieved, we can undertake the selection of the surface equipment.
Designing a UBD Operation
A basic four-step process can be applied to determine the options and requirements for drilling underbalanced:
1. Determine BHP requirements.
2. Identify the drilling fluid options.
3. Establish the well design and perform flowing modeling.
4. Select the surface equipment.
BHP RequirementsIn 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. 12.4).
Drilling Fluid Systems
Correct selection of the fluid system used in UBD is the key to a successful UBD operation (Fig. 12.5). Initial fluid selection for UBD operations is classified into five fluid types based primarily on equivalent circulating density: gas, mist, foam, gasified liquid, and liquid.
Final fluid selection for UBD operations can be extremely complex. Key issues 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, and fluid source availability, as well as staying below the reservoir pressure at all times, the primary objective for drilling underbalanced, must be considered before a fluid design is finalized.
Gaseous fluids are basically the 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.
Characteristics of gas drilling are listed next:
- Fast penetration rates.
- Longer bit life.
- Greater footage per bit.
- Good cement jobs.
- Better production.
- Minimal water influx required.
- Possibility of slugging.
- Possibility of mud rings in the presence of fluid ingress.
- Relies on annular velocity to remove cuttings from the well.
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 then 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. The following lists the characteristics of mist drilling:
- It is similar to gas drilling, but with addition of liquid.
- 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.
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. The fact that stable foam has some natural inherent viscosity, as well as fluid-loss-control properties, makes foam 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.
The next fluid system that is often used is a gasified fluid system. In these systems, 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.
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/Liquid RatiosFig. 12.6 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.
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. First, with hydrocarbon influx, there is the danger of a downhole fire or explosion. Second, 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.
Drillpipe InjectionCompressed gas is injected at the standpipe manifold, where it mixes with the drilling fluid. Fig. 12.7 shows a typical drillpipe gas-injection configuration in a well. 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 BHPs can be achieved using this system.
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 then 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 especially 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.
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 InjectionAnnular 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 then tied back to surface using a modified tubing hanger to suspend the tieback string. Gas is injected in the casing liner annulus to facilitate the drawdown required during the drilling operation. Fig. 12.8 shows typical annular gas-injection configuration in a well.
The tieback string is then 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 BHPs during the drilling operation. The drawback with this type of operation is that the hole size 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.
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.
However, 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 InjectionFig. 12.9 shows typical parasite-string gas-injection configuration in a well. The use of a small parasite string strapped to the outside of the casing for gas injection is used only in vertical wells. 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.
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.
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.
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.
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 RegimesTo 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 and, again, 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. 12.10.
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.
Circulation Design Calculations
In designing a UBD circulation system, the bottomhole pressure must be maintained below the reservoir pressure. But the surface separation system must have sufficient capacity to handle the flow rates and pressures expected while drilling. The 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. These factors are discussed next.
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 not only of BHP but also reservoir characteristics like permeability, porosity, length of reservoir exposed to the wellbore, drainage radius, and the 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; that is, 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.
Environmental Considerations. Either 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.
Wellbore Stability. 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 in evaluating the feasibility of a reservoir as a candidate for UBD.
Annular Bottomhole Pressure vs. Gas Injection RateThe graph in Fig. 12.11 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, the gas is compressed at the bottom of the well, and the gas expands as it rises to the surface of the well. As more gas enters the system, the friction pressure in the well increases, as shown in Fig. 12.12. 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.
If we combine these two effects into a single curve, then we get the typical pressure vs. gas rate curve, as shown in Fig. 12.13. 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.
BHP StabilityTo 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.
However, the operating envelope cannot tell the entire story. 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, pressures, and temperatures. 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. 12.14), 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. 12.15 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. 12.16 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. 12.17) 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.
Hole CleaningFig. 12.18 shows annular liquid velocity vs. gas-injection rate and liquid-flow rate. Hole cleaning while UBD horizontally must be monitored closely. There is a reduced fluid rheology (a very thin, nonsolids-suspending mud), turbulent two-phase flow, and, normally, an increased rate of penetration (ROP). A result of two-phase flow is accelerating mud and cuttings transport velocities (because of gas expansion) as the fluid moves upward from the bit.
The main areas of concern for hole cleaning are the region where the hole angle is from 45 to 50° and the region immediately behind the bit. The area immediately behind the bit can become the critical hole-cleaning area because there is limited reservoir inflow. Liquid-phase velocity and hole cleaning in this area depend only on the fluid(s) and rate(s) being pumped or injected down the drillstring.
Two-phase hole cleaning is largely dependent on the same criteria as for single-phase. Hole-cleaning efficiency and solids transport are primarily controlled by liquid-phase velocities and solids concentration. Studies and field experience have shown that removal of cuttings is more efficient with two-phase fluid. The addition of a gas medium generates a turbulent flow regime, which minimizes solids bed formation. Liquid velocity is the critical parameter controlling the system
’ s ability to transport solids. From experience, it has been concluded that a minimum liquid-phase annular velocity of 180 to 200 ft/min is required in a wellbore with a deviation greater than 10°.
In UBD, as soon as the bit penetrates the reservoir, reservoir fluids start to flow into the wellbore. At this stage, the stabilized multiphase flow regime in the well prior to reservoir fluid entry must be adjusted to account for inflow without upsetting the circulating system or moving out of the UBD window already established. The rate of reservoir fluid inflow depends, in part, on the drawdown and reservoir rock properties (the differential pressure between circulating BHP and reservoir pressure). There are a number of models that can be used to estimate the reservoir fluid inflow based on the rock and fluid parameters. However, the reservoir rock properties are fixed, and the only variable is the drawdown to control reservoir fluid inflow.
As previously defined, the inflow performance of a well represents the ability of the reservoir to produce fluids under a given condition of drawdown. The reservoir fluid inflow performance is the most important parameter in UBD, operationally and economically, because of its impact on well production and the safety operating envelope.
The sole purpose of drilling any well underbalanced is to create conditions that induce the flow of reservoir fluid into the well while drilling, minimize reservoir damage, and optimize production of reservoir fluid from the well. Therefore, the relationship between the BHP and reservoir inflow is one of the most important parameters in UBD design and management. It is important that the BHP and reservoir inflow rate are managed and maintained within the defined operating envelope. Where the surface pressure, production rate, or BHP cannot be maintained within safe levels or underbalanced, drilling operations must cease immediately.
Downhole Equipment for UBD Operations
PWD sensors have proved invaluable in every UBD operation to date when they have been included in the drillstring and operated without downtime. However, quite a number of these sensors have proved problematic because of the vibration problems and fast drilling rates encountered with UBD. Adding a downhole gauge or sensor on the injection side and in the drillstring definitely enhances the UBD operation and helps the team optimize the drilling process and increase the knowledge of the reservoir.
Conventional MWD Tools in UBD
The most common technique for transmitting MWD data uses the drilling fluid pumped down through the drillstring as a transmission medium for acoustic waves. Mud-pulse telemetry transmits data to the surface by modifying the flow of mud in the drillpipe in such a way that there are changes in fluid pressure at surface. It involves the sequential operation of a downhole mechanism to selectively vary or modulate the dynamic flowing pressure in the drillstring and thereby sends the real-time data gathered by the downhole sensors. This variation in the dynamic pressure is detected at the surface, where it is demodulated back into the real measurements and parameters from the downhole sensors.
Signal strength at the surface depends on many factors including the mud properties, drillstring arrangement, flow rate, signal strength generated at the tool, telemetry frequency, and many others. Experience to date indicates that this enhanced mud-pulse telemetry system is best applied to scenarios with a maximum gas percentage of 20% (by volume at the standpipe), and this ratio can be extended somewhat depending on well depth, profile, liquid-phase fluid, drillstring/bottomhole assembly (BHA), pumping pressure, and flow rates. Further reductions in borehole pressure are possible with gas lift applications in which N 2 is injected into the annulus. A major disadvantage of the mud pulse is that it will not work if high-quality foam is needed. For such fluids, an electromagnetic method must be used.
If annular gas injection is used, we have a single-phase fluid down the drillstring, and conventional MWD systems can be used. If drillstring gas injection is considered, the option of using electromagnetic MWD tools must be considered.
Electromagnetic Measurement While Drilling (EMWD)
Electromagnetic telemetry transmits data to the surface by pulsing low-frequency waves through the Earth. The first application of PWD measurements has been primarily for drilling and mud performance, kick detection, and ECD monitoring.
Float valves are necessary for UBD to prevent influx of reservoir fluids inside the drillstring either when tripping or making connections. It must be recognized that there is pressure below nonreturn valves. The positions of the float valve in the drillstring depend on the tools in the BHA and the policy of the operating philosophy underpinning the safety management of the operation. The number of float valves in the BHA and the drillstring is also a matter of company policy consistent with perceived risks and management thereof. If the drilling float valve(s) should all fail, the well may have to be circulated to kill weight fluid and a string trip undertaken to replace or repair the float valves.
It is good practice to install a float valve in the top of the drillstring, often referred to as the string float valve because it aids operational efficiency by reducing the time it takes to bleed off the pressure before making connections while also serving as an additional barrier in the event of a failure of the float valves in the BHA. This top valve is often a wireline retrievable float valve that can be retrieved, as access through the string is required. In general, a double float valve is installed just above the BHA and a further double float valve is installed above the bit so that there is redundant service. Two types of non ported drillstring floats that are commonly used are the flapper and plunger floats.
The underbalanced deployment valve has been designed to eliminate the need for snubbing operations or the need to kill the well to trip the drillstring during UBD operations. During UBD operations, the well is allowed to flow; this results in a flowing or shut-in pressure in the annulus at surface. With any significant pressures while tripping the drillstring, it has been necessary to either use a snubbing unit or kill the well.
The deployment valve is run as an integral part of the casing program, allowing full-bore passage for the drill bit when in the open position. When it becomes necessary to trip the drillstring, the string is tripped out until the bit is above the valve, at which time the deployment valve is closed and the annulus above the valve bled off. At this time, the drillstring can be tripped out of the well without the use of a snubbing unit and at conventional tripping speeds, thus reducing rig time requirements and providing improved personnel safety. The drillstring can then be tripped back into the well until the bit is just above the deployment valve, at which time, the deployment valve can be opened and the drillstring run in to continue drilling operations.
The deployment valve can either be run with the casing using an external casing packer for isolation or with a liner hanger and tieback. Once installed, the valve is controlled through pressure applied to the annulus, created between the intermediate and surface casing. Or the valve can be controlled through dual control lines. When using a snubbing unit, the operator not only has to consider the actual cost of the snubbing service but should also include rig-up and rig-down time together with the increased tripping times, in terms of the overall daily drilling costs.
Surface Equipment for UBD Operations
The surface equipment for UBD can be broken down into four categories:
- Drilling system.
- Gas-generation equipment.
- Well-control equipment.
- Surface separation equipment.
If the platform process or export equipment is used when drilling underbalanced, it is considered a separate issue and, therefore, is not included in this chapter.
Drilling Systems. Hole size and reservoir penetration, as well as directional trajectory, determine whether coiled tubing or jointed pipe is the optimal drillstring medium (Table 12.6). If the hole size required is larger than 6⅛ in., jointed pipe may need to be used. For hole sizes of 6⅛ in. or smaller, coiled tubing can be considered. The size of coiled tubing currently used for drilling operations is between 2 and 2⅞ in. OD. This is because of many factors, including the flow rate through the coil, pressure drop through the tubing, WOB, profile of the well, maximum pickup weight, both in-hole and surface equipment, and weight of the coiled tubing itself. Occasionally, the ideal coiled tubing for an operation may be excluded because of such factors as crane or transport limitations or that the life of the coil may not be economical. Generally, coiled tubing has several advantages and disadvantages compared to jointed pipe systems. For jointed pipe systems, drillstring properties and tripping under pressure must be considered. If hole size and trajectory permit, coiled tubing is the simplest system to drill underbalanced.
Natural Gas. If natural gas is used for UBD, a natural gas compressor may be required; this would need to be reviewed once the source of the gas is known. Most production platforms have a source of high-pressure gas, and in this situation, a flow regulator and pressure regulator are required to control the amount of gas injected during the drilling process.
Cryonic Generation. The use of tanked nitrogen could be considered on onshore locations, where a large truck could be used for its supply. Cryogenic nitrogen in 2,000-gal transport tanks provides high-quality nitrogen and utilizes equipment that is generally less expensive. Liquid nitrogen is passed through the nitrogen converter, where the fluid is pumped under pressure prior to being converted to gas. The gas is then injected into the string. Generally, the requirement is for the nitrogen converter and a work tank, with additional tanks being provided as necessary. For operations in excess of 48 hours, the requirement for liquid nitrogen could be quite large, and this can result in logistical difficulties. To move away from tank transport for large nitrogen-dependent drilling operations, the use of nitrogen generators is often recommended offshore.
Nitrogen Generation. A nitrogen generator is no more than a filtering system that filters nitrogen out of the atmosphere. A nitrogen generator uses small membranes to filter the air. Oxygen-enriched air is vented to the atmosphere, and nitrogen is boosted to the required injection pressure. Fig. 12.19 shows a nitrogen-generation system.
A nitrogen generator is 50% efficient. In real terms, if 1,500 ft2/min of nitrogen is required, then 3,000 ft2/min of air needs to be pumped into the generator. A full nitrogen system for 1,500 ft2/min would comprise of three or four large air compressors, a nitrogen generator, and a booster compressor. This equipment will take up significant deck space on an offshore rig or platform. Fig. 12.20 shows the nitrogen generation equipment rigged up on a jackup.
Another issue associated with nitrogen generation is the purity of the nitrogen itself. Purity varies depending on the amount of nitrogen required. At 95% purity (by mole), 5% oxygen is delivered. Although this is not enough oxygen to reach explosive levels, it is sufficient oxygen to cause corrosion problems. The corrosion is further worsened when salt brine systems are used at elevated temperatures (Fig. 12.21).
Jointed-Pipe Systems. The conventional BOP stack used for drilling is not compromised during UBD operations. The conventional BOP stack is not used for routine operations and is not used to control the well except in the case of an emergency (Fig. 12.22).
A rotating control-head system and primary flowline with ESD valves is installed on top of the conventional BOP. If required, a single blind ram, operated by a special Koomey unit, is installed under the BOP stack to allow the drilling BHA to be run under pressure.
Coiled-Tubing Systems. Well control is much simpler when drilling with reeled systems. A lubricator can be used to stage in the main components of the BHA, or if a suitable downhole safety valve can be used, then a surface lubricator is not required. The injector head can then be placed directly on top of the wellhead system (Fig. 12.23).
The reeled systems can then be tripped much faster and the rig-up is therefore much simpler. However, one consideration relating to reeled systems is the cutting strength of the shear rams. Verification is required to ascertain that the shear rams will cut the tubing and any wireline or control-line systems inside the coil. For a standalone operation on a completed well, an example stack-up is shown.
Snubbing Systems. If tripping is to be conducted underbalanced, a snubbing system must be installed on top of the rotating control-head system (Fig. 12.24). Current systems used offshore are called rig-assist snubbing systems. A jack with a 10-ft stroke is used to push pipe into the hole or to trip pipe out of the hole. Once the weight of the string exceeds the upward force of the well, the snubbing system is switched to standby, and the pipe is tripped in the hole using the drawworks. The ability to install a snubbing system below the rig floor allows the rig floor to be used in conventional drilling. The snubbing system is a so-called rig-assist unit. This unit needs the rig drawworks to pull and run pipe. It is designed to deal only with pipe light situations. Snubbing on an onshore rig where there is no space under the rig floor to install a snubbing unit must be conducted on the rig floor. To facilitate snubbing, so-called push/pull units are installed on the rig floor (Fig. 12.25).
Rotating Diverter Systems. The principle use of the rotating diverter system is to provide an effective annular seal around the drillpipe during drilling and tripping operations. The annular seal must be effective for a wide range of pressures and for a variety of equipment sizes and operational procedures. The rotating control-diverter system achieves this by packing off around the drill pipe. The rotating control-head system consists of a pressure-containing housing where packer elements are supported between roller bearings and isolated by mechanical seals.
There are currently two types of rotating diverter: active and passive. The active type uses external hydraulic pressure to activate the sealing mechanism and increase the sealing pressure as the annular pressure increases. The passive type, normally referred to as rotating control-head systems, uses a mechanical seal. All surface BOP systems have limitations in both the amount of pressure they can seal off and in the degradation of the sealing equipment from the flow and composition of the different reservoir fluids and gases over time, regardless of the type of surface BOP control system chosen.
Rotating Control Heads (Passive Systems). Rotating control heads are passive sealing systems (Fig. 12.26). Rotating control heads have given excellent service for more than 30 years, particularly in the air and air-foam drilling industry. The rotating control head is playing an increasingly important role in UBD, provided that its inherent pressure limitations are not being extended. The conventional, original rotating control head was developed in the 1960s. This is a low-pressure model and has been used on thousands of underbalanced and overbalanced drilled wells. It is designed to operate at 500 psi rotating and 1,000 psi static. It is capable of rotating up to 200 rpm and uses a single stripper rubber. It is currently used in many underbalanced operations in the United States. The current rotating control heads are rated to a static pressure of 5,000 psi and a rotating pressure of 3,000 psi with 100 rpm.
Rotating BOPs (Active Systems). The rotating blowout preventer (RBOP), as it is commonly referred to under its trade name, is probably the most significant piece of equipment developed, with the biggest impact being its ability to drill underbalanced with jointed pipe in a variety of different reservoir and wellbore scenarios. The rotating control-head system must be sized and selected on the basis of the expected surface pressures. A well with a reservoir pressure of 1,000 psi does not need a 5,000-psi rotating control-head system. A number of companies offer rotating control-head systems for UBD (Fig. 12.27).
Separation Equipment. The separation system has to be tailored to the expected reservoir fluids. A separator for a dry-gas field is significantly different from a separator required for a heavy-oil field. The separation system must be designed to handle the expected influx, and it must be able to separate the drilling fluid from the return well flow so that it can be pumped down the well once again.
The surface separation system in UBD can be compared with a process plant, and there are many similarities with the process industry. Fluid streams while drilling underbalanced are often described as four-phase flow because the return flow comprises of oil, water, gas, and solids.
The challenge of separation equipment for UBD is to effectively and efficiently separate the various phases of the return fluid stream into individual streams. Several approaches in separation technology have emerged recently (Fig. 12.28). The chosen approach depends largely on the expected reservoir fluids.
Careful design of the surface separation system is required once the reservoir fluids are known. Dry gas is much simpler to separate than a heavy-crude or gas-condensate reservoir. However, the separation system must be tailored to reservoir and surface requirements. This requires a high degree of flexibility, and the use of a modular system helps to maintain such flexibility.
The use of a modular system for offshore operations is often recommended because lifting capacity of platform and rig cranes is regularly limited to 15 or 20 tons. To reduce the total footprint of a separation package, vertical separators are generally used offshore as opposed to the horizontal separators used in onshore operations. In a lot of situations, the separator is the first process equipment that receives the return flow out of a well. Separators can be classified, as shown in Table 12.7. Separation of liquids and gasses is achieved by relying on the density differences between liquid, gas, and solids. The rate at which gasses and solids are separated from a liquid is a function of temperature and pressure.
Horizontal and vertical separators can be used. Vertical separators are more effective when the returns are predominantly liquid, while horizontal separators have higher and more efficient gas handling capacities. In horizontal separators, well returns enter and are slowed by the velocity-reducing baffles (Figs. 12.29 and 12.30).
Data Acquisition. The data acquisition used on the separation system should provide the maximum amount of information about the reservoir obtainable while drilling. It should also allow for a degree of well testing during drilling. Furthermore, the safety value of data acquisition should not be overlooked because well control is related directly to the pressures and flow rates seen at surface.
Erosion Monitoring. Erosion monitoring and prediction of erosion on pipe work is essential for safe operations. The use of nondestructive testing technology has been found to be insufficient in erosion monitoring. An automated system using erosion probes is currently deployed, and this allows accurate prediction of erosion rates in surface pipe work.
Completing Underbalanced Drilled WellsThe majority of wells previously drilled underbalanced could not be completed underbalanced. The wells were displaced to an overbalanced condition with kill fluid prior to running the liner or completion. Depending on the completion fluid type, some formation damage would take place. The damage is not as severe for completion brine as with drilling mud because there are no drilled cuttings and fines in the brine. However, reductions in productivity of 20 to 50% have been encountered in underbalanced drilled wells that were killed for the installation of the completion.
If the purpose of UBD is reservoir improvement, it is important that the reservoir is never exposed to overbalanced pressure with a nonreservoir fluid. If the well has been drilled underbalanced for drilling problems and productivity improvement is not impaired, then the well can be killed and a conventional completion approach can be taken.
A number of completion methods are available for underbalanced drilled wells: liner and perforation, slotted liner, sandscreens, and barefoot. All of these options can be deployed in UBD wells. The use of cemented liners in an underbalanced drilled well is not recommended if the gains in reservoir productivity are to be maintained.
Regardless of the liner type run, the installation process for the completion is exactly the same. It is assumed that a packer-type completion is installed. The production packer and tailpipe are normally run and set on drillpipe with an isolation plug installed in the tailpipe. If the well is maintained underbalanced, well pressure will normally require the production packer and tailpipe to be snubbed into the well against well pressure. The use of pressure-operated setting equipment in underbalanced drilled wells is not recommended. A mechanically set production packer should be used.
Installation of Solid Liner. Using solid pipe for the liner is no different from snubbing in drillpipe or tubing. The shoe track of the liner must be equipped with nonreturn valves to prevent flow up the inside of the pipe. The liner is normally run with a liner packer, and the liner can be snubbed into the live well. Once on bottom, the liner hanger and packer are set and the reservoir is now sealed. If zonal isolation is required, ECPs must be run at predetermined intervals. Once the liner is set, the pipe must be perforated to obtain flow. This can be achieved using the normal procedures, but it should be remembered that any fluid used must maintain the underbalanced status.
Installation of a Perforated Liner or a Sandscreen. The main disadvantage of running a slotted liner or sandscreen in an underbalanced drilled well is that isolation is not possible across the slotted section of the liner or screen with the BOPs. The use of plugged slots that dissolve once the liner is installed downhole is not deemed safe for offshore operations. The pressure integrity of each slot would have to be tested prior to running each joint, and this is not feasible.
The use of special blanking pipe in sandscreen also adds further complications to the installation procedures. Running a slotted pipe or screen into a live well cannot be done safely because even if all the holes are plugged, the potential for a leak is too great. The only way to install a slotted liner in a live well is by using the well as a long lubricator and by isolating the reservoir downhole.
There are mechanical methods of downhole isolation available for the running of a slotted liner. The underbalanced liner bridge plug system is one of the systems currently on the market. This system allows a retrievable plug to be set in the last casing. This isolation plug is released by a retrieving tool that is attached to the bottom of the slotted liner. This retrieving tool unseats the isolation plug and then swallows the isolation plug or packer. The swallowing action of the retrieval tool ensures that the plug and retrieving tool are rigid and can be run to TD without hanging up in the open hole. Both the packer and retrieval tool are specifically designed to be released by the liner. If necessary, the well can be lubricated to kill fluid on top of the plug and displaced via the slotted liner when the drillstring is sealed by the rotating diverter. The procedure for running a slotted liner and the completion in an underbalanced drilled well is outlined in the following diagrams (Fig. 12.31).
Completion Running. The main problem with running the completion in a live well is the installation of the subsurface safety valve control line. Once the control line is connected, the BOPs no longer seal around the pipe. Once again, therefore, the simplest method is to isolate the reservoir prior to running the completion.
In the case of the completion, the production packer with a plug installed in the tailpipe is snubbed into the live well, and the production packer is set on drillpipe. The packer assembly would be lubricated into the well by utilizing the snubbing well-control system.
Once the production packer is set, the drillpipe can be used to pump completion fluid to provide an additional barrier that can be monitored if required. The completion is now run conventionally. The isolation plug in the tailpipe is retrieved during the well commissioning. Once again, before pulling this plug, the fluid must be displaced out of the completion string. This can be achieved with coiled tubing or with a sliding sleeve. Once the completion has been installed, the well is ready for production. No cleanup or stimulation is required in the case of underbalanced drilled wells.
Workover of an Underbalanced Drilled Well
The workover procedure is a reversal of the completion running (i.e., a suspension plug is installed in the production packer tailpipe, and the well is lubricated to kill fluid). After retrieving the completion, the packer-picking assembly is run to the packer depth, and the well is returned to an underbalanced condition prior to retrieving the packer. This ensures that formation-damaging kill fluid does not come into contact with the reservoir at any time.
Underbalanced Drilled Multilateral Wells
The setting of the production packer with a mechanical plug allows the lower leg in a multilateral well to be isolated and remain underbalanced while the second leg is drilled. After running the liner in the second leg, the completion can be run and a second packer can be installed and stabbed into the lower packer. If leg isolation is required, a flow sleeve can be installed at the junction to allow selected stimulation or production as required. Re-entry into both legs is also possible by use of a selective system. However, more detail as to the exact requirements from a multilateral system must be reviewed.
Drilling a multilateral well underbalanced with the main bore producing can be done, but the drawdown on the reservoir is small. A further setback is that the cleaning up of the lateral is difficult if the main bore is a good producer. Getting sufficient flow through the lateral to lift fluids can be a challenge.
Health Safety and Environmental IssuesBecause UBD involves working on a live well, a hazard operational ("hazop") analysis is required for the full process. To this end, a flow chart has been created that shows all the elements in the UBD process. Using the diagram, each element can be analyzed for input and output and the diagram has also been used to good effect to ensure that all items of an UBD system are reviewed during the hazop. It also allows procedures and documentation to be reviewed for all parts of the UBD system.
Fig. 12.32 shows an analysis path together with the interaction of the various elements. The drilling liquid system (1), the gas system (2), and the reservoir characteristics (3) specify the well system (4). The well system (4) specifies the well control system (5), which has impact on the drilling fluid system (1). This loop must be resolved before continuing to the surface separation system (6). This influences the rig fluid system (7), which must also be compatible with the drilling liquid system (1). The platform process system (8) must be consistent with the surface separation system (6) as well as the overall platform system. Multiple iterations are necessary to bring all systems into alignment.
Environmental Aspects. The UBD system is a fully enclosed system. When combined with a cuttings-injection system and an enclosed mudpit system, a sour reservoir can be drilled safely using a UBD system. The pressures and flow rates are kept as low as possible. It is not the intention to drill a reservoir and produce it to its maximum capacity. A well test can be carried out while drilling underbalanced to provide some productivity information. The hydrocarbons produced during the UBD process can be routed to the platform process plant, exported, or flared. There is work currently being undertaken to reduce flaring and recover the hydrocarbons for export. In a prolific well, a significant amount of gas might be flared during the drilling process. Recovering this gas provides an environmental benefit and an economic benefit. Oil and condensate recovered are normally exported via a stock tank into the process train.
Safety Aspects. Besides the full hazop, substantial crew training is required for UBD. A typical drilling crew has been instructed during its entire career that if a well kicks, it must be shut in and killed. In contrast, during UBD, the single item to be avoided is to kill the well. This may undo all the benefits of UBD. Working on a live well is not a normal operation for a drilling crew, and good training is required to ensure that accidents are avoided.
The UBD process is more complex when compared to conventional drilling operations. Gas injection, surface separation, and snubbing may be required on a well. If the hydrocarbons produced are then pumped into the process train, it is clear that drilling is no longer a standalone operation.
The reservoir is the driving force in the UBD process. The driller must understand the process and all the interaction required between the reservoir—the liquid-pump rate, the gas-injection rate, and the separation and process system—to drill the well safely. When tripping operations start, the well must remain under control. Snubbing pipe in and out of the hole is not a routine operation, and a specialized snubbing crew is normally brought on to snub the pipe in and out of the hole.
The extra equipment also brings a number of extra crewmembers to the rig. So besides a more complex operation, a number of service hands are on the rig which now must start working with the drilling crew. Yet the drilling crew will move back to conventional drilling once the well is completed. The drilling crew must be trained in this change of operating practice.
When a number of wells will be drilled underbalanced in a field, it may be a consideration to batch drill the reservoir sections. This saves mobilization, and it also sets a routine with the drilling crew. It must be stated that few accidents occur during UBD. This is mainly because of the high emphasis on safety during live well operations.
There are limitations, as well as advantages, to UBD. Before embarking on a UBD program, the limitations of the process must be reviewed. There are technical limitations as well as safety and economic limitations to the UBD process. The following are conditions that can adversely affect any underbalanced operation:
- Insufficient formation strength to withstand mechanical stress without collapse.
- Spontaneous imbibitions because of incompatibility between the base fluid used in the UBD fluid and the rock or reservoir fluid. Use of a nonwetting fluid can prevent or reduce this situation.
- Deep, high-pressure, highly permeable wells presently represent a technical boundary because of well control and safety issues.
- Noncontinuous underbalanced conditions.
- Excessive formation water.
- High-producing zones close to the beginning of the well trajectory will adversely affect the underbalanced conditions along the borehole.
- Wells that require hydrostatic fluid or pressure to kill the well during certain drilling or completion operations.
- Slimhole or drilling conditions that result in a small annulus create high backpressures because of frictional forces.
- Wells that contain targets with significant pressure or lithology variations throughout.
Wellbore Stability. Wellbore stability is one of the main limitations of UBD. Borehole collapse as the result of rock stresses is one issue to consider. The other issue is chemical stability, which is a problem seen in shale and claystone formations. Both these issues can have serious implications in UBD. Defining maximum drawdown and reviewing chemical compatibility with the proposed drilling fluids is a key issue in the feasibility of UBD.
Water Inflow. Water inflow in a depleted reservoir can cause severe problems in an underbalanced drilled well. If the flow rate is high enough, the well will be killed as a result of the water influx. Gas lifting a well that produces water at a high rate is almost impossible. Care must be taken that the water leg in a depleted reservoir is not penetrated when drilling underbalanced.
Directional Drilling Equipment. Directional drilling equipment can have limitations on UBD. Hydraulic operated tools cannot be used in underbalanced wells, and if a gasified system is used, the MWD pulse systems may not work. Certain motors and other directional equipment may be prone to failure as a result of the rubber components becoming impregnated with the gas used. Explosive decompression of rubber components is a consideration when selecting equipment.
The higher torque and drag seen in underbalanced wells (as much as 20 to 100%) may also prevent certain trajectories from being drilled underbalanced. The higher torque is caused by the reduced buoyancy combined with the lack of filter cake on the borehole wall.
Unsuitable Reservoir. The reservoir may not be suitable for UBD. A highly porous, high-permeability reservoir can provide too much inflow at low drawdown. It is important that the perceived benefits of UBD are kept in mind when planning for underbalanced operations.
Safety and Environment. The health, safety, and environment issues of a UBD operation may prove to be too complicated to allow UBD to proceed.
Surface Equipment. The placement of the surface equipment may prove to be impossible on some offshore locations. There can be problems with rig-floor height and with deck space or deck loading. Both the wellhead equipment and the surface separation equipment must be carefully designed to fit the platform or rig.
Training in UBD
The entire platform/rig crew must be trained in underbalanced techniques. Once the crew understands what is to be achieved, operations will run more smoothly and with fewer problems and accidents. Documentation, policies, and procedures should not be forgotten when considering training.
The number of crew required for UBD is still considered large; 15 to 20 extra crewmembers are required for full UBD and completion.
The business driver behind the technology must never be forgotten. If the benefits cannot be achieved, the project must be reviewed. Improvements seen from UBD are twice the penetration rate and triple the production rate.
P = pressure, m/Lt2 , psi
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SI Metric Conversion Factors
|ft||×||3.048*||E – 01||=||m|
|ft 2||×||9.290 304*||E – 02||=||m2|
|gal||×||3.785 412||E – 03||=||m3|
Conversion factor is exact.