Monitoring downhole pressures and flow rates critical for underbalanced drilling

S.D. Butler, A.U. Rashid, and R.R. Teichrob
Flow Drilling Engineering Ltd.
Calgary

True underbalanced drilling, and not just flow drilling, requires thorough engineering and monitoring of downhole pressures and flow rates to ensure the formations are drilled without formation damage.

Underbalanced drilling involves intentionally manipulating the bottom hole circulating pressure so that it is less than static reservoir pressure. This underbalanced pressure condition allows reservoir fluids to enter the well bore while drilling continues, preventing fluid loss and many causes of formation damage.

Applied correctly, this technology can address problems of formation damage, lost circulation, and poor penetration rates. Another important benefit of drilling underbalanced is the ability to investigate the reservoir in real time.

Underbalanced drilling is a relatively new technology that can help operators maximize the profitability of oil and gas plays. While extreme productivity increases can be realized in some cases, the technology is not applicable to all reservoirs and should not be applied without thorough engineering.

Underbalanced conditions can be achieved in various ways, and the optimum choice for a particular well will require input from drilling, production, reservoir, and geological personnel.

Many pools are excellent candidates for underbalanced drilling, but operators must be cautious in deciding whether to drill a well underbalanced. Incremental production can often be realized from mature pools by using underbalanced drilling techniques. Also, costly drilling problems can be minimized or eliminated.

Underbalanced drilling technology must be applied carefully, however, because these projects are technically complex and involve a number of uncertainties. As a result, these projects require comprehensive engineering analysis before, during, and after the actual drilling operation to ensure that the maximum benefit is realized.

Why drill underbalanced?

Underbalanced drilling can increase profits, not only by generating additional revenue during drilling, but also by reducing drilling and completion costs. There are numerous ways in which underbalanced drilling techniques can help improve profit, including eliminating problems with lost circulation, increasing penetration rates, allowing real-time reservoir investigation, reducing completion and stimulation costs, and improving well bore productivity by decreasing formation damage.

In drilling a horizontal well bore, the productive rock is exposed to damaging fluids for long periods of time, increasing the likelihood of flow-restricting formation damage. Mature pools that have relatively low reservoir energy may be unable to clear this damage from productive rock immediately adjacent to the well bore.

There are various mechanisms that can cause this damage during conventional drilling. A reduction in return permeability because of solids blocking the pore throats and filtrate invasion increasing liquid saturations are the main mechanisms of formation damage.¹ Formation damage can decrease production and reduce economic field life.

Because horizontal stimulations are costly, complex, and often ineffective, there may be an economic advantage to drill the well underbalanced. Reservoir flow during underbalanced drilling can minimize or prevent near well bore damage, often eliminating the need for stimulation. Typically, wells drilled underbalanced have production tubing run as the final operation by the drilling rig.

Lost circulation can tremendously increase the cost of a drilling project. Additional costs result when drilling fluids, which may contain lost circulation or expensive fluid-loss additives, are lost to fractured, low-pressure, or high-permeability reservoirs. In addition to the loss of these fluids, drilling costs may increase because of lost rig time because of differential sticking. In the worst case, the drillstring may be lost if stuck pipe cannot be freed. The occurrence of these problems can result in drilling costs significantly higher than those associated with drilling the well underbalanced.

Penetration rates generally decrease as the length of the horizontal well bore increases. This decrease in penetration rate is due mainly to increasing hole drag which reduces the effective weight on bit.

Typically, underbalanced drilling requires less weight on bit to maintain the same penetration rate as in neutral or overbalanced drilling. Because of the decreased hydrostatic pressure at the bit face, the rock being drilled fails more easily. The high-energy circulating fluid helps reduce chip hold-down, allowing the bit to cut new rock instead of pulverizing old cuttings.²

Underbalanced drilling provides an unprecedented opportunity to examine a reservoir as it is being drilled. Proper data acquisition and interpretation allow engineers and geologists to identify and locate geologic anomalies such as fractures, tight zones, pinch outs, discontinuities, and water zones. This information can be used by reservoir and production engineers to determine the degree of reservoir heterogeneity, the optimum horizontal well bore length, and the number and orientation of future development wells.

Effective monitoring of production rates permits real-time decisions regarding changes in drilling depth, well bore orientation, and overall section length. In some cases, horizontal lengths have been reduced 75% from that planned when economic production rates have been achieved, saving the operator significant drilling costs.

Creating underbalance

An underbalanced condition can be achieved by varying a number of parameters. Numerous choices exist in well bore geometry, injection fluid types, fluid ratios, surface control procedures, and injection methods. The optimum choice depends upon site-specific reservoir conditions, such as type, drive mechanism, quality, formation depth, pressure, target drawdown, and the particular requirements of the operator.

Injection liquid and gas types and ratios are most commonly manipulated to control bottom hole pressure. Because most operators have specified the hole and tubular size, the prescribed geometry is investigated first. It must be recognized, however, that the hole/tubular sizes specified possibly may not allow or may severely limit the drilling and successful unloading of drilled solids and produced and injected fluids.

In new wells this may not be a significant problem because hole/tubular sizes can often be modified. In reentry applications where the hole and casing sizes are often fixed, compromises are required to satisfy all parameters.

The unique pressure regimes present and the effect of injection fluid types and volumes on sandface drawdown and subsequent inflow are the least understood aspects of underbalanced drilling. Reservoir drawdown must be controlled, or at very least monitored, to ensure underbalanced conditions are maintained. There is a unique opportunity during underbalanced drilling to analyze the relationship between drawdown and inflow using accurate data monitoring and multiphase flow simulation.

Multiphase flow modeling software should incorporate a choice of several distinct fluid flow models to commingle injected and produced fluids, ultimately defining flow regimes and velocities. Calculated bottom hole circulating pressure is used during planning to describe the full operating envelope of the system and the sensitivity of that system to variations in reservoir inflow. It is extremely difficult to predetermine the inflow from a horizontal well bore during underbalanced drilling operations.

Therefore, a range of inflow rates is designed into the program to ensure successful completion. Typically, inflow at 50%, 100%, and 150% of the anticipated production rate is modeled and evaluated. It is critical to ensure that the pressure drop calculations across the horizontal section conform to equilibrium of production, drawdown, and reasonable back pressure held at surface.

A test matrix comprised of differing flow rates at specified drawdown is performed. The objective is to construct an operational envelope under which the probability of success is maximized. The envelope should contain severe enough end points in pressure drawdown and corresponding flow rates to encompass actual well site conditions. This analysis ensures effective contingency planning is in place should reservoir inflow markedly differ from that anticipated.

On site services

A multidisciplinary approach is required from the initial planning stage. The drilling program should include input from the operator's reservoir, geology, drilling, and production personnel, in addition to service company experts.

Underbalanced drilling requires the integration of diverse services and equipment. All aspects of the operation must be organized cooperatively to increase the probability of success. Distinct and very specialized services must be integrated to form a coherent operating entity. Only through this approach can a truly optimum well plan be designed and executed.

Well site engineering

Traditionally, engineering support for conventional drilling operations would usually be provided from the office. A drilling engineer would write a drilling program, gain consensus from operations regarding operational merit, then entrust a competent field foreman with field execution. The geology department necessarily required a professional on site, because real-time interpretation of samples returned to the surface was integral to the overall success of the well. Because the success of drilling an underbalanced well requires real-time interpretation of drilling and production parameters, engineering support should be on location also.

Underbalanced drilling operations require personnel on site who can, in addition to monitoring engineering constraints, ensure all services are coordinated and controlled through a central focal point. Field observations have shown that underbalanced services often are not well coordinated, resulting in additional costs to the operator.

Field personnel are usually uncomfortable with underbalanced drilling procedures that deviate from conventional drilling techniques and are therefore sometimes unable to ensure that all aspects of the job are carried out as specified in the underbalanced drilling program. The on site drilling foreman may not be familiar with underbalanced operations, and this often leads to a sense of general confusion at the well site. Because daily costs associated with underbalanced operations are extremely high, it is imperative that unnecessary delays on site and between the field and office are avoided.

As drilling proceeds, reservoir inflow will likely change. On site engineering personnel may have to respond immediately with an injection blend ratio change to maintain optimum underbalanced drilling conditions. Injection blend changes are based on updated multiphase flow model results. Computer modeling may be used during drilling to evaluate sandface drawdown, develop inflow performance relationships and, in combination with mass balance monitoring, provide well bore productivity information.

This analysis provides a unique opportunity to infer qualitatively the productivity of a given interval within a lateral section. Additionally, localized reservoir inflow data can be used to help correlate geological sample analysis with electric log response.

Fluids handling

Proper fluids handling procedures are critical during underbalanced drilling operations. The closed system must allow for sample catching and safe venting of produced gases and must allow rig personnel both to flow and kill the well under all operating conditions (drilling, tripping, circulating, making connections, etc.).

The closed system should initially contain all liquids and gases. Well bore effluent must pass through a properly sized and constructed separator vessel. Gas exits the vessel to a flare stack equipped with an automatic ignition system and flame propagation blocks. Oil and water are separated within the vessel and pumped to independent fluid gauging and storage facilities on site.

All hydrocarbon-bearing tanks should be vented to the flare stack. If storage capacity is insufficient, oil can be transported to external production facilities, and water will be reused or deposited at a specified disposal facility. As an additional safety precaution, berms with protective liners should be placed around all fluid-containing tanks.

The surface equipment layout should be specified to avoid unnecessary rig crew exposure to noxious fumes and flammable liquids. The equipment layout must maintain adequate separation distances from the wellhead and all external sources of ignition. Separation criteria must meet applicable regulator or operator specifications. The flare stack should be positioned downwind.

Rotating flow diverter

Control of the well while drilling is normally accomplished by using a rotating flow diverter, which provides a means to flow oil or gas from the well while maintaining a closed system.

There are two basic designs of flow diverters currently in use: One type applies hydraulic pressure to an annular rubber element which seals around the drillstring. The second type involves a friction-fit rubber sealing element which uses annular pressure to increase seal effectiveness around the drillstring.

The type of blowout prevention (BOP) equipment required depends on the type of well being drilled, depth, expected annular pressures, presence of sour or sweet fluids, and operating procedures.

Fundamentally, the equipment must provide an alternative way to bleed down or kill the well if the diverter system should fail.³ Because the well is live during the drilling of the pay zone, there should be a sufficient quantity of kill-weight fluid available on location.

Injection gas

Air, liquid nitrogen, on site-generated nitrogen, cleaned exhaust gas, or locally produced methane can be used for injection with the liquid phase.

Each alternative has physical and economic constraints which must be analyzed to determine the appropriate injection gas for a project. Any one gas source does not immediately preclude the use of any other gas source.

• Air. The use of air as a means to lower bottom hole pressure and therefore increase rate of penetration is well documented technology with a long history of success. It is important to recognize, however, that air drilling technology is limited to drilling essentially "dry" wells and does not accommodate the unloading of large volumes of oil or water from a horizontal section.

  In addition, a significant risk may exist in air drilling hydrocarbon zones. Combustible mixtures can be created at any point in the system when air is used as an injection gas. This can result in downhole fires or surface explosions. Downhole fires can create fishing jobs, loss of the bottom hole assembly, and possibly the well itself.

  If air is contemplated as an injection gas, it is strongly recommended to use a blended system containing a predetermined concentration of an inert gas such as nitrogen. Exact air/nitrogen mix ratios must be determined by in situ condition combustion analysis.^4-5 Appropriate lab tests can be performed by combustion engineering specialists. Liquid nitrogen costs have been reduced by as much as $35,000/day by use of this technique in Canada.

  Significant equipment mobilization costs and relatively high fuel consumption can be a concern with air drilling. When coupled with downhole fire risk and possible corrosion effects caused by high oxygen content, the economic attractiveness of drilling with air is reduced.

• Liquid nitrogen. Bulk or liquid nitrogen was the standard injection gas used when underbalanced drilling technology was in its infancy. It was initially used because of its inert properties and ready availability.

  Field experience has shown invoice costs for liquid nitrogen to be as high as 25% of total drilling costs. In a properly designed underbalanced well, nitrogen injection rates will almost always change with increased lateral length and production, thereby linking nitrogen product cost with injection pumping rate. This economic relationship may severely limit the ability of an on site engineer to justify nitrogen injection rate increases when required. Accurate cost estimation and control are extremely difficult because necessary nitrogen injection rate increases could severely exceed the project costs.

  Typically, high daily cost, including volume used and associated pumping charges, often precludes the use of bulk nitrogen, given the alternatives available in the market. If a horizontal project requires relatively small amounts of nitrogen over a short period of time, however, it may make economic sense to use bulk nitrogen instead of mobilizing large amounts of equipment to provide an alternative source of injection gas. Also, because liquid nitrogen is essentially pure, observed corrosion problems in the presence of connate water and trace oxygen are not an issue.

• On site generated nitrogen. A very economical alternative to liquid nitrogen is the use of on site nitrogen-generation equipment. The economic affect of increased nitrogen rates no longer exists, because nitrogen consumption and cost are no longer related. On site-generated nitrogen is typically charged at a flat rate per day, up to the capacity of the unit.

  This equipment includes air compressors and a nitrogen-generation unit which uses a filter to separate nitrogen from compressed air. Because of the molecular disparity between nitrogen and oxygen, the nitrogen passes through the filter medium while the oxygen component permeates to atmosphere. The nitrogen is then boosted to line pressure and injected downhole.

  It should be noted that the capacity of an on site nitrogen generator is limited by the ability of the compressors to deliver sufficient quantities of source air at adequate input pressure. It is highly recommended to require suppliers to perform a maximum deliverability test prior to drill out. The test should be performed at both an unconstrained oxygen content and at maximum nitrogen purity. This test confirms maximum deliverability under actual operating conditions without reliance on published data, thus avoiding inconvenient surprises should higher rates be required during the drilling operation.

  Field observations have shown that nitrogen-generation systems with catalog deliverability of 1,500 scfm at 5% O2 delivered as low as 1,015 scfm under specific operating conditions. Actual nitrogen purity and system deliverability must therefore be addressed. Typically, wells have been drilled with a nitrogen purity of ~95%.

  Overall deliverable rates from the outlet side of the nitrogen generator decrease significantly with demand for increased nitrogen purity. Ambient temperature and ground level elevation can also have significant effects on compressor deliverability and, therefore, the overall rate available. It should be noted that this specified 95% purity does not consider system flammability, since formal combustion studies have not been performed.

  Past experience using on site nitrogen generators has shown this level to be safe. Corrosion has been observed due to oxygen in the presence of produced water. Detailed corrosion studies complete with treatment programs should be performed where wells are to be drilled in the presence of connate water.

• Cleaned exhaust gas. Compression is required at the rig site to supply sufficient volumes of injection gas at standpipe pressure. After an effective filtration process, exhaust gas from the compressor prime movers can be used as an inert injection gas. This new technology appears to be a highly economic alternative to other sources of injection gas.

• Methane. Methane gas can be a viable alternative to inert gases. Economics are a function of predicted injection rates, location of gas source, and predicted time of use. The operator must consider the cost of linking an existing sales line into a drilling operation as well as the direct costs of burning sales gas at a flare.

Typically, low injection rates or short-duration drilling operations may preclude the use of sales gas. Some advantages of using sales gas include its relative compatibility with indigenous hydrocarbons and lack of corrosion concerns.

Survey techniques

Conventional survey techniques are ineffective for drilling with a compressible fluid. Two options exist for transmitting survey information to surface during underbalanced drilling. The use of electromagnetic measurement while drilling (EMWD) tools, which transmit signals to surface through the earth instead of through the drilling fluid, is the preferred method of transmitting survey information. The signals can be interrupted, however, by high-resistivity formations in the area.

Wire line transmission of survey information is required in areas where EMWD tools are ineffective. This method involves the use of a conductive line run inside the drill pipe between the downhole sensor and the surface. A wet-connect system, which allows connections to be made without removing the entire wire line, is used to minimize wire line retrieval during connections.

Field experience, however, has shown wire line-conveyed surveys can require excessively long connection times. Also, failure to reestablish positive wet connections of the wire line after making the drill pipe connection can result in additional delays.

Data acquisition

Operating parameters must be monitored continuously during underbalanced drilling. Small changes in some parameters can often affect the equilibrium of the system profoundly. Initially, acquisition processes involved manual data recording on paper and have evolved to sophisticated computerized systems linked via satellite to networked central data processing.

Field experience has shown both extremes to be unacceptable-the first due to data resolution and lag time issues, and the second due to extreme cost and unnecessary complexity.

Because of these issues, it is highly desirable that operators make each service company responsible for collecting its own data and ensuring data integrity. Each company must properly format its data to make them readily available for the on site engineer to compile and analyze.

The importance of appropriate data resolution cannot be overstated. Fig. 1 [12764 bytes] and Fig. 2 [14471 bytes] demonstrate the importance of continuous monitoring at an acceptable data rate. Fig. 1 shows how the gas production rate varies over three randomly picked consecutive kelly-downs.

The gas production rate was plotted based on the industry standard 30-min sample intervals and appears to be relatively constant.⁶ The same data, based on 5-min samples, are shown in Fig. 2. The gas production rate is highly variable because of the dynamic state of the operation. Without continuous monitoring of operating parameters, these fluctuations would go unnoticed and the actual state of underbalance would be impossible to determine. Again, on site underbalanced drilling engineers are needed to assess the operation in real time.

Operations

A clear, fundamental understanding of drilling technology is required to design and supervise drilling operations on an underbalanced well. The individual responsible for managing the project should be a drilling expert with horizontal and underbalanced drilling experience.

Caution must be exercised in applying conventional knowledge to underbalanced projects. Often, signs that warn of impending downhole problems during conventional drilling may not be observed during an underbalanced operation.

For example, during a conventional drilling operation increasing injection pressure may indicate poor hole cleaning and packoff with drilled solids. Decreased returns of solids at the shale shaker may confirm this problem. Because of the closed, compressible underbalanced drilling system, pressure response at the standpipe may not be noticed in a timely manner. Because returns are routed to a closed surface system, solids returns are extremely difficult to quantify. The sample volume at catch pots is the only way to quantify solids returns volume.

An underbalanced drill ing operation is complex and requires thoughtful analysis prior to the making of any changes in flow conditions. Underbalanced drilling personnel should be able to analyze operating parameters constantly to determine if drilling problems are developing.

Maintaining underbalance

The well should flow from drill out of the intermediate shoe to landing of the tubing. The underbalanced condition of the system must be maintained across the entire length of the well bore.

Many factors can interact to make it technically impossible to maintain underbalance, including hydraulic cross sections, produced fluid properties, multiphase flow behavior, degree of drawdown and resulting inflow, and superficial fluid velocities. These factors must all be considered when an operational envelope is used. Operational envelopes should be developed for a wide range of operating parameters. Fig. 3 [13801 bytes] describes bottom hole pressure vs. nitrogen-injection rate for one particular set of parameters.

The bold line in Fig. 3 represents reservoir pressure and suggests that acceptable nitrogen injection rates would lie between 9 and 41 cu m/min. An optimum rate can only be determined by examining operational factors such as annular velocity distributions and hydraulic horsepower available to the downhole motor. The rate must be sufficiently high to take full advantage of gas lift effects without incurring excessive friction losses and gas lift costs.²

It is important to remember that this envelope is only valid for a given set of operating parameters. Also, the factors mentioned above can combine to shift this graph in any direction. Thus, it is crucial that operating parameters and well bore production rates be monitored and modeled on a timely basis during drilling.

Routine drilling

Normal operating procedures can also affect the overall success of the project. Routine drilling operations such as making connections, surveying, and tripping can introduce high-density slugs into the system, making it difficult to maintain underbalance at the sand face.

Each drill pipe connection introduces an annular fluid slug into the system. Annular fluid slugging occurs primarily during pump off periods. The severity of annular slugging depends on fluid concentration in the injection mixture as well as the type of hydrocarbon produced and the capacity of the well to flow under its own energy.

If a well produces relatively small amounts of gas, for example, and there is a relatively large fluid concentration, a definite fluid slug will form in the bottom hole.

Field observations have clearly indicated that methane and nitrogen in a system will segregate in the well bore during circulation interruptions.

Consider a low-energy gas well. Precise production data monitoring after a connection shows decreased gas production followed by a significant gas peak. As the fluid slug formed by separation of injected fluids moves to surface, gas production is reduced. Eventually, the slug is purged from the well, and the resultant compressed gas behind the slug expands at surface and manifests itself as an increase in production.

Avoiding annular slugging in wells that are marginal producers is extremely difficult. Purging the drill pipe with gas prior to a connection or trip can reduce this effect. The only way to eliminate fluid slugging is to increase gas purge times to include the annulus as well as drill pipe. Obviously, this is not a tenable solution because of the very long pumping periods necessary. In addition, observed pipe drag goes up significantly as the well is "dried" by gas flow.

A well that is producing liquid hydrocarbons would continually exhibit fluid slugging due to formation loading. Prolific fluid producers can actually kill themselves during times of pump off. Restarting gas/fluid injection down drill pipe can become highly problematic under these circumstances. Often, circulation cannot be reestablished, and the bit must be tripped back and staged into the well in a graduated manner. The well is eventually blown down, and the bit finally arrives on bottom to recommence drilling operations. A method that successfully deals with this problem is to close the large orbit valve on the flow line to the separator just prior to kelly down.

The resultant back pressure placed on the well keeps the fluid level at equilibrium with the system long enough to complete a connection without excessive fluid loading.

Rate of penetration

After a discussion of fluid slugging, it becomes apparent that actual bottom hole pressures can be significantly affected, and the objective of drilling underbalanced may be compromised. Uncontrolled drilling rates using conventional drill pipe can result in an unexpected overbalanced condition downhole.

If there is insufficient time for each fluid slug, containing increased concentrations of drilled solids, to circulate through the system and back to surface before another connection is made, the slugs can accumulate and create enough backpressure to overbalance the well.

High-resolution production data aid the engineer in determining optimum connection frequency. Observations show the definite peaks and valleys in production data correlated to fluid slug arrival at surface (Fig. 2 [14474 bytes]).

The phenomenon of fluid slugging has extremely important ramifications regarding the maximum sustainable penetration rate that can be achieved. If only one fluid slug is observed at surface between connections, the system is in equilibrium with injection, production, and penetration rates. If more than one slug is observed, the system is no longer in equilibrium.

Maintaining or increasing that penetration rate would eventually result in overwhelming the system with fluid. It is therefore paramount to monitor production data closely during drilling.

The effective rate of penetration is defined by the overall pumping time necessary to purge a slug of fluid and cuttings from a well. High instantaneous penetration rates will be offset by increased pumping time on bottom. Also, extreme drilling rates could load the well with enough drilled solids to cause packoff and sticking problems, regardless of slug position in the well bore.

Obviously, wells capable of producing prodigious rates of gas would be least affected by this phenomenon. While it is possible to minimize these effects, current technology does not allow them to be eliminated when conventional drill pipe is used. Coiled tubing drilling, however, may reduce or eliminate fluid slugging.

Misconceptions

There are many misconceptions about underbalanced drilling, because it is a relatively new technology. Four common misconceptions are:

• Surface hydrocarbon production confirms the underbalanced condition of the system.

• Air drilling principles apply to underbalanced drilling.

• More nitrogen in the drilling fluid is better.

• Underbalanced drilling can save marginal wells.

Many people assume that production of hydrocarbons during drilling confirms that the well is being drilled underbalanced. Unfortunately, this is not the case and is a dangerously simplified assumption.

Large pressure drops, compounded by localized reservoir inflow, may exist over the horizontal section resulting in underbalanced conditions near the casing and overbalanced conditions at the bit. This means that hydrocarbons seen at surface may be produced near the casing while formation damage or fluid loss occurs at the bit. Obviously, this situation defeats the purpose of underbalanced drilling.

In highly permeable formations, the relationship between hole cleaning, massive inflow, and resultant bottom hole pressure at the bit is also poorly understood. Operators often experience difficulty in transferring weight to the bit because of hole drag problems. Annular velocity calculations, based on flow rate to surface and hydraulic cross section, suggest hole cleaning should be adequate.

Analysis and field observations, however, have shown that the following phenomenon occurs: The fixed hydraulic cross section in the casing/drillstring interval allows a maximum rate of fluid and gas to pass under the pressure differential of bottom hole reservoir pressure and surface operating pressure. For wells of extreme deliverability, well bore flow may reach this limit.

Additional fluid and gas injected must necessarily be lost to the formation because the hydraulic cross section is saturated.

Analysis of annular velocity through the entire lateral section would therefore show an effective velocity rate of zero at or near the bit. It follows that fluids and drilled cuttings would not be transported past this point and would be lost, creating formation damage and a potential packoff in the open hole section.

In short, hydrocarbon production only confirms that the well is underbalanced at some point along the horizontal well bore. Only by direct measurement or modeling of annular pressure can underbalanced drilling conditions be confirmed.

Field experience has shown there is a fundamental lack of understanding regarding drilling with a multiphase fluid. The application of air drilling principles to underbalanced drilling projects can be catastrophic. Ill-conceived attempts to improve hole cleaning by decreasing liquid injection rates while simultaneously increasing gas injection rates may cause problems. This often results in an insufficient liquid component in the multiphase flow stream to provide energy to transport drilled cuttings.

There is, however, enough liquid present to wet the cuttings and create a paste-like consistency, resulting in hole packoff and sticking problems. Increasing liquid injection rates to clean a well while maintaining underbalance is counterintuitive to most individuals with air drilling experience. Also, increased gas injection rates may actually increase bottom hole pressure because of additional frictional losses.

Many underbalanced drilling operations are compromised by injecting excess nitrogen. When an increase in nitrogen injection shows a positive response in terms of bottom hole pressure and rate of penetration, there is a tendency for operators to increase the nitrogen rate further to try to increase these benefits.

There is a limit to the amount of nitrogen that a given system can tolerate, however. The purpose of injecting nitrogen is to decrease hydrostatic head and, consequently, bottom hole circulating pressure. Increases in nitrogen rate also increase fluid velocities and resultant frictional pressure losses, however.

If too much nitrogen is injected, excessive frictional losses because of fluid velocity can overcome the benefits of reduced hydrostatic head. This effect is illustrated in Fig. 3 [13801 bytes] for nitrogen rates greater than 20 cu m/min. This operational envelope is for a specified hole size, pipe size, formation depth, and open hole length. Drilling, production, reservoir, and geological considerations must be evaluated when choosing optimum nitrogen-injection rates.

Underbalanced drilling can improve the productivity of some wells, but it cannot affect the ability of a reservoir to transmit fluid. If productivity is restricted by formation damage near the well bore, then underbalanced drilling may result in improved productivity. If the reservoir is tight and transmits hydrocarbons slowly, however, underbalanced drilling may not be economically feasible because little or no productivity increase would result. It is crucial, therefore, to understand why a given well or pool flows poorly before deciding to attempt underbalanced drilling.

Economics

An underbalanced drilling operation may cost approximately the same as a conventional well when associated completion costs are considered. Additional costs associated with underbalanced drilling include nitrogen supply, closed system surface equipment, data acquisition equipment, and electromagnetic MWD tools.

The savings in completion costs can be substantial. Additionally, in some cases, the value of hydrocarbons produced during drilling can pay for the entire drilling operation. In other cases, incremental hydrocarbon production can increase the overall profitability of the play.

Elimination of costly drilling problems may justify the additional expenses. One of the most important benefits of underbalanced drilling is the ability to evaluate the reservoir in real time. This allows the operator to characterize the reservoir more accurately and fine tune exploitation strategies for current and future wells in the play.

Acknowledgment

The authors wish to thank Rob Peters for his assistance in preparing this article.

References

1. Gray, R., and Bird, K., "Laboratory Evaluation of Underbalance Formation Damage Compared to Neutral and Overbalance Conditions," 1st International Underbalanced Drilling Conference & Exhibition, Oct. 2-4, 1995, The Hague, The Netherlands.

2. Butler, S.D., and Gregory, G.A., "Multiphase Flow Considerations in Underbalanced Drilling of Horizontal Wells," BHR Group 7th International Conference-Multiphase 95, June 7-9, 1995, Cannes, France.

3. Eresman, D., "Underbalanced Drilling-A Regulatory Perspective," the Canadian Association of Drilling Engineers/Canadian Association of Oilwell Drilling Contractors Spring Drilling Conference, Apr. 14-16, 1993, Calgary.

4. Teichrob, R.R., "Low-pressure reservoir drilled with air/N2 in a closed system," OGJ, Mar. 21, 1994, pp. 80-89.

5. Mehta, S.A., et al., "High-Pressure Flammability of Drilling Mud/Live Heavy Oil Mixtures in Pure Air and Nitrogen/Air Mixtures For Use In Underbalanced Drilling Operations," UNITAR Conference, February 1995, Houston.

6. Butler, S.D., Teichrob, R.R., and van Regen, N.C.R., "An Engineered Approach to Underbalanced Drilling," presentation at the CADE/CAODC Spring Drilling Conference, Apr. 19-21, 1995, Calgary.

The Authors