UNDERBALANCED DRILLING GUIDELINES IMPROVE SAFETY, EFFICIENCY

Dale Eresman
Energy Resources
Conservation Board Calgary

Although many operators follow safe and efficient practices in underbalanced drilling, the use of consistent procedures and equipment configurations can improve operations.

In underbalanced drilling, the primary means of well control, the hydrostatic head of the drilling fluid, is lost either unavoidably because of hole problems (such as abnormally high pressure or lost circulation) or intentionally because of economics or to prevent formation dam age.

The Alberta Energy Resources Conservation Board (ERCB) first studied the potential growth in underbalanced drilling after the American Petroleum Institute (API) annual meeting in San Diego in 1991. At the time, underbalanced drilling was widely used on horizontal wells in the Austin chalk in central Texas, primarily to prevent formation damage.1 Because of complications with underbalanced drilling, however, several rigs have been destroyed by fire.

Concerned about these incidents, the API addressed underbalanced drilling practices during the revisions of Blowout Prevention Equipment Systems For Drilling Wells (API RP 53).2 Unfortunately, underbalanced drilling was tabled by the RP 53 committee, and the recommendations never developed beyond the draft stage.

Underbalanced drilling is not new in Alberta, but the frequency of its use and types of applications certainly are. To keep abreast of the technology, the ERCB reviews in detail every new drilling application, visits well sites and meets with operators regularly, participates on API committee RP 53, and visits with other regulatory agencies. 2

The ERCB is challenged with balancing potentially conflicting mandates of well control and conservation. That is to say, the ERCB must ensure that adequate well control is maintained, yet it must allow industry the flexibility to experiment with unconventional well control techniques, such as some of those used in underbalanced drilling, that may increase recovery of Alberta's hydrocarbon reserves.

Operational guidelines are being developed in close cooperation with industry. The final guidelines will be consistent with the existing standards of well control practices in Alberta, yet applicable for underbalanced drilling operations world wide. Until formal guidelines are completed in Alberta, operators interested in underbalanced drilling should work closely with the Energy Resources Conservation Board in preparing site-specific programs.

Although underbalanced drilling is often associated with horizontal wells, the majority of underbalanced drilling operations in Alberta are conducted on vertical wells.

DEFINITION

API committee RP 53 proposed in draft Section 13 "that underbalanced drilling is any drilling operation where an influx of formation fluids is allowed into the well bore, circulated out and controlled at the surface. The influx can occur as a result of severe and uncontrollable lost returns and/or by a conscious decision of the operator to drill with an influx as a means of enhancing drilling performance."2

The ERCB's studies in Alberta indicate that an influx does not always occur. In fact, many of the underbalanced drilling operations are actually balanced or only marginally underbalanced. These operations may not fit into the API definition and would perhaps more appropriately be termed "drilling on the edge."

The ERCB proposes the following definition for underbalanced drilling: An operation is underbalanced drilling if the hydrostatic head of the drilling fluid is intentionally designed to be less than the pressure of the formation drilled. The fighter hydrostatic head of the drilling fluid may occur naturally or may be induced by adding a gas such as air or nitrogen to the liquid phase of the drilling fluid. The lighter hydrostatic head may result in an influx of formation fluids which must be circulated from the well and controlled at the surface.

UNDERBALANCED DRILLING

From a practical perspective, drilling underbalanced is an effective method to prevent lost circulation and differential pipe sticking, An underbalanced fluid column can also help in drilling through abnormally pressured, low-volume, gas-bearing formations above the objective formation.

From an economical perspective, underbalanced drilling can help prevent formation damage, increase penetration rates, increase bit life, and possibly eliminate expensive formation stimulation work. These benefits can make many new and existing pools economically feasible to develop.

The ERCB is receiving more applications for new wells and the re-entry of wells in old pools previously considered uneconomical. Many of these operations plan underbalanced drilling.

From a regulatory perspective, the improved recovery of hydrocarbons helps fulfill the ERCB's conservation mandate.

Regulators need to facilitate the testing of such new technology, prior to setting firm standards for its use,

ALBERTA

Underbalanced drilling is not exactly, new technology in Alberta; rather, the technology might best be described as recently improved. Air and air/foam drilling have been used for a Ion, time. Some of the major fields in Alberta were drilled with air and air/foam.

For example, the wells in the Jumping Pound field west of Calgary were drilled from below the surface casing to about 1,500 m or deeper with air or air/foam. The primary reason for drilling underbalanced was to increase bit penetration rates. Drilling with air was stopped in these wells prior to penetration of the objective sour formation.

More recently (since 1988), many, wells in the Sturgeon Lake and Bonnie Glen fields were drilled underbalanced because of severe lost circulation problems in the Leduc formation.

Air drilling has been used on shallow gas wells in eastern Alberta for many years. Air drilling is typically used in the northeast to prevent severe lost circulation and in the southeast to prevent formation damage.

Many wells in the Banff formation in the mountains and foothills and the Milk River formation in southern Alberta have required underbalanced drilling. In these wells, the abnormally high pressured zones are above the objective formations.

These wells are drilled underbalanced to eliminate having to increase the fluid density. Increased drilling fluid density reduces penetration rates and may also induce lost circulation above or below the abnormally high pressure zone. (Note: These zones contain low-volume, high-pressure gas which often bleeds down after the formation is drilled. If the formations do not bleed down, they may have to becased off or the density of the drilling fluid may have to be increased prior to penetration of the objective formation.)

Interestingly, much of the same equipment and procedures used in the past are used today to create underbalanced drilling conditions intentionally, and many of the concerns not fully resolved then are being raised again.

BLOWOUT PREVENTION

Underbalanced drilling techniques vary regionally. The amount and type of equipment installed is usually directly related to the magnitude of surface pressure an operator believes can be controlled safely and the nature of the reservoir fluids (sweet or sour) expected in the well. Generally, underbalanced drilling requires blowout preventers (BOPs) that can do the following simultaneously:

• Permit drilling to proceed while controlling annular pressure

• Allow connections to be made either with the well flowing or shut in

• Allow tripping of the drillstring under pressure

• Provide for backup annular control in case of diverter failure

• Provide for a choke manifold arrangement that allows annular pressure to be varied so it will not exceed the equipment's rated working pressure

• Provide a means to bleed off pressure or to kill the well independent of the diverter system

• Provide a means to shut in the well quickly and safely.

SURFACE BOP EQUIPMENT

The variety of equipment (drilling rigs, service rigs, and coiled tubing units) used in underbalanced drilling has resulted in a wide variation in the types and configuration of BOPs used. The ERCB Class III well servicing stack and some type of diverter system are generally used (Fig. 1). 3

The diverter system must be capable of providing an effective annular seal during drilling or tripping pipe in or out of the well. This annular seal must be effective over a wide range of pressures and for a variety of equipment and procedures.

Surface BOPs have limitations, regardless of the type chosen. The key to making the right selection is careful consideration of the possible well conditions and the type of pipe rotation to be conducted through the diverter. One of the most important considerations in selecting BOP configuration is how the bit will be rotated (conventional rotary table, top drive or power swivel, or mud motors for slide drilling).

For BOP stack design, the primary difference between balanced and underbalanced drilling is the diverter system.

For drilling and service rig BOPs, enough spacing should be allowed in the BOP stack to allow closing of the blind ranis below the bit when the bottom hole assembly (BHA) is stripped out of the hole, if the well cannot be controlled with kill density fluid. Also, care should be taken to ensure that the drillstring is not pushed out of the hole by well pressure. If this potential problem exists, snubbing equipment should be considered.

Kill and bleed-off lines are an integral part of any BOP system. In underbalanced drilling, a diverter line is installed between the diverter and the remainder of the BOPs. At least one bleed-off and one kill line are installed at some other point on the BOP stack.

Some bleed-off lines have an hydraulically operated valve (HCR) installed in it or an emergency shutdown device on the diverter line. In Alberta, an HCR is required for normal drilling wells but not for servicing operations. 3 Currently, there are no regulated design specifications for diverter lines. Typically, if a drilling rig is used for underbalanced drilling, all lines will be installed according to the ERCB's drilling BOP requirements. The requirements specify only flanged connections between the BOP stack and the choke manifold. A service rig used for the same operation, however, only follows the servicing regulations. Servicing regulations allow the use of hammer-union connections, rather than flanges, in the lines.

Which bleed-off system is most appropriate remains to be determined by industry and regulators.

STRIPPER

The stripper annular preventer is simply a second conventional annular preventer mounted at the top of the BOP stack. A flow line is installed on a spool between the existing annular preventer and the stripper annular preventer.

The stripper preventers have been used in slide drilling and with top drives rotating smooth pipe through the diverter. The kelly cannot be rotated through them.

Potential differential pressures must be considered carefully if pipe will be rotated through any stationary preventer used as a stripper. On one operation, for example, the drilling rig was drenched with oil after the preventer failed to provide an adequate seal while the pipe was rotated through it.

ANNULAR PACK OFF

The annular pack off is installed above the existing annular preventer. The pack-off device uses a single elastomeric element that depends either on hydraulic pressure or on will bore pressure from below the packing element to seal the annulus.

These devices are used primarily to strip pipe under low or moderate differential pressure. They may be appropriate for slide drilling if differential pressures are low.

On one recent well, the pack off failed, and the rig was sprayed with oil. In this case, the pack off was used while the pipe was rotated with a power swivel.

ROTATING HEAD

Rotating heads have given excellent service for years in air and air/foam drilling. The rotating head has a role in underbalanced drilling providing its pressure limitations are observed.

Rotating heads can be used for both sliding and rotary drilling with a conventional kelly. Most manufacturers will not guarantee specific pressure limitations, and the API does not recognize rotating heads as blowout preventers. The API does, however, recognize the rotating head as a diverter. 4

Rotating heads have been used successfully on air, air/foam, and air/mist operations during slide drilling and drilling with a hexagonal kelly. No rotating head failures have been reported to the ERCB in recent years.

ROTATING BOP

The rotating blowout preventer (RBOP) is probably one of the most significant new pieces of equipment developed specifically for underbalanced drilling. The RBOP allows for conventional kelly rotation with surface pressures up to 10,500 kPa (about 1,500 psi).3

The RBOP was developed for drilling horizontal wells in the Austin chalk in Texas. Because of the pressures and flow rates in the Austin chalk, conventional rotating heads and annular preventers were often inadequate. Many operators, contractors, and regulators in Texas believe the RBOP contributed to the resurgence in Austin chalk activity because the tool allowed safer underbalanced drilling of the horizontal wells.

Until recently, the use of RBOPs was limited because of the cost and because they could not be used with a top drive or power swivel. A new generation RBOP is now compatible with top drive and power swivel systems. The RBOP is one of the best rotating diverter systems and is also effective for slide drilling.

Many operators are using RBOPs more frequently, especially for drilling higher risk wells (with high pressure or H,S). In Alberta recently, the first critical sour well intentionally drilled underbalanced used an RBOP.

COILED TUBING

Coiled tubing units are gaining in popularity for underbalanced drilling operations. The typical BOP stacks include a four-ram unit consisting of tubing rams, blind rams, cutter rams (shear rams), and slip rams. A riser is placed above the rams and must have sufficient length to lubricate tools in or out of a live well. An hydraulic pack off at the top of the riser provides an annular seal while the tubing slides in or out of the well (Fig. 2).

From a well control perspective, the main advantage of coiled tubing is the use of continuous pipe. Because there are no connections to be made during tripping, there is no danger of flow up the drill pipe resulting from the failure of downhole floats or a parted drillstring.

Other advantages include reduced tripping time and the ability to use hard wire for measurement-while-drilling (MWD) and bottom hole pressure tools. Hard wiring these tools back to surface makes information transmission possible even in a gasified fluid environment. The ability to monitor bottom hole pressures continuously, allows for fine tuning of the underbalanced state. Such adjustments can be very useful because pressures encountered while drilling can change continuously because of pore pressure changes or lost circulation.

Because many companies that operate coiled tubing units are also affiliated with nitrogen services, both the drilling and the drilling fluid service may be supplied by, the same company. On mans, operations, the combined services have been a definite plus.

In northeastern Alberta, coiled tubing units are used routinely for open hole completions in severely underpressured shallow gas wells. These operations use air for the fluid medium.

ERCB inspectors have witnessed several of these jobs and in the beginning found some companies did not install sufficient riser length to lubricate the entire drilling assembly from the well. The result was that the well was allowed to flow temporarily at the wellhead until the drilling assembly cleared the wellhead master valve. This problem has since been rectified, with appropriate-length risers now used.

SUBSURFACE BOP

Fluid entry into the drillstring during tripping or making connections must be prevented. Most operations use either inside BOPs or float subs. If floats are used, usually two will be installed.

For air, air/mist, or air/foam operations the subsurface BOP equipment should also include a fire float. The fire float is needed to extinguish downhole fires, should they occur.

DRILLING FLUIDS

The drilling fluid systems used in underbalanced drilling include the following: air, air/mist, air/foam, nitrogen, nitrogen/mist, nitrogen/foam, crude oil, crude oil/nitrogen, diesel fuel/nitrogen, produced water/nitrogen, freshwater, and gas/mist.

Just prior to the preparation of this article, the ERCB received its first application to use gas/mist as a drilling fluid. The proposed well will be drilled horizontally into an existing sweet gas storage reservoir.

AIR

Compressed air is probably the oldest form of underbalanced drilling fluid in use. Air is still a popular choice for drilling the hard rock sections of deep wells and for completing shallow subnormal-pressured gas wells along the eastern flank of Alberta.

In the past few years, many of the shallow gas operations have used coiled tubing units.

Air/mist and air/foam systems are being used with varying degrees of success for drilling subnormal-pressured oil wells. The biggest drawback with these systems is the potential for downhole fires.

Downhole fires have been reported at three locations in Alberta since December 1992. BHAs, steering tools, and downhole motors have been destroyed by these fires. In at least one incident, the casing was damaged and required repair.

The regulatory concern with downhole fires is limited to the fire's effect on casing integrity and the potential for loss of well control up through the drillstring if parting occurs above the drillstring floats.

NITROGEN

Nitrified drilling fluids are becoming more popular. More than 50% of underbalanced drilling operations (excluding conventional air drilling) use nitrogen in one form or another. Pure nitrogen, nitrogen/mist, and nitrogen/foam systems are alternatives to air systems. Many operations have used these types of nitrogen systems in combination with coiled tubing drilling operations.

Nitrogen combined with crude oil, produced water, or diesel fuel is also used frequently with success. Several innovative methods have been used to nitrify the liquid phase of the drilling fluid for site-specific needs:

• Standpipe connection

  The nitrogen is simply tied in at the standpipe. The nitrogen is then mixed with the liquid phase of the drilling fluid, pumped down the drill pipe, and returned to surface through the annulus.

• Parasite string

  A small diameter (25 mm) coiled tubing string is strapped permanently to the outside of the intermediate casing and cemented in place with the casing. Parasite strings are most often used in horizontal wells. The coiled tubing is connected to the inside of the casing through a specially designed sub near the bottom of the casing (Fig. 3).

  The point of entry into the casing is still in the vertical portion of the well. Nitrogen is pumped through the parasite string into the casing/drill pipe annulus. Consequently, only the annulus in the vertical part of the well is nitrified.

  Because nitrogen is not pumped through the drill pipe, MWD pulse tools, which function best in a continuous liquid column, are not affected by the nitrification of the drilling fluid. Also, having the drill pipe filled with non-nitrified fluid allows for faster well kill if necessary.

• Dual annuals

  The dual-annulus procedure is similar to that of the parasite string. A second, uncemented casing string is set in the well. Nitrogen is injected down the casing/casing annulus instead of down the parasite string.

WATER AND CRUDE OIL

In normally pressured or overpressured reservoirs, water-based or crude oil systems may be underbalanced without the injection of air or nitrogen. If the reservoir pressure exceeds the hydrostatic pressure exerted by the column of drilling fluid, the underbalance is created naturally. Drilling a well affected by a pressure maintenance scheme is an example in which this type of system has been used successfully in Alberta.

Many operators use water-based systems to drill horizontal wells underbalanced in the Austin chalk in Texas. These systems have been effective in areas of the Austin chalk where reservoir pressure gradients are greater than that of freshwater. These systems are generally less expensive because no nitrogen or air services are needed and no special modifications are required for MWD tools.

SURFACE EQUIPMENT

The fluid handling system design depends on the characteristics of the well and the type of drilling fluid system used.

Some air, air/mist, and air/foam systems only need an earthen pit to contain residual foam and drill cuttings or to flare gas. With an air-type system, if fluid separation is required because of produced reservoir fluids, no closed vessels should be used because of the potential for explosion. Separation should be completed in open tanks using mud/gas separators. Because sour wells should be drilled with entirely closed systems, air may have very limited application for use on sour wells.

Nitrogen, nitrogen/mist, and nitrogen/foam systems can use closed vessels and are therefore applicable to sour service conditions. In nitrogen/foam systems, the closed vessels primarily break the foam. Nitrogen/foam systems have been used recently in Alberta to complete sour gas wells with H2S contents greater than 10%.

Nitrified oil or nitrified produced water systems use vessels designed to separate gas, oil, and water streams and to settle out drilled solids to prepare the drilling fluid for re-use in drilling the well.

Straight water-based or crude oil systems need only very simple separation systems, consisting of as little as a mud/gas separator in an open tank if the well is sweet. If the well is sour, closed separation tanks may be necessary. Fig. 4 is a simplified flow diagram of a typical fluid handling setup for either nitrified liquid or straight liquid systems.

Provision must be made for the storage and disposal of produced fluids, for flaring sour gas, and for the control of transient explosive vapors from open tanks or closed tank vents.

The Alberta Recommended Practices for well testing and fluid handling (to be published soon) will help operators design safe fluid handling systems for underbalanced drilling. 7 Underbalanced drilling operations have several special considerations for fluid handling system design:

• If the well contains sour gas only, a completely closed system can be used, and any vented gas, including tank vapors, must be flared. In Alberta, ERCB sour gas flaring requirements apply.'

• Air systems are limited to open tank separation of fluids only.

• Adequate separation and storage facilities should be available in case reservoir fluids are produced.

• Foam breaking may be necessary to prevent the accumulation of large volumes of foam returning from the well.

• Separation and storage facilities must accommodate drilled solids.

• Low-pressure flaring of gas may necessitate the use of special flame arrestors and check valves to prevent flashback to vessels or the well bore.

• Separation equipment must be designed based on the proposed underbalanced drilling pressure and the expected flow rates of the various gas and liquid streams from the well. If no mud/gas separators are installed on the rig, the separator should also be capable of separating mud and gas in case a well kill is required.

• The fluid handling system must be capable of catching drill cutting samples.

• Propane blankets may be required to reduce explosive potentials in closed circulation tanks.

WELL-SITE SUPERVISION

Underbalanced drilling is one of the most demanding operations for a well-site supervisor. The ideal supervisor should be knowledgeable and experienced in open hole drilling, including horizontal and sour well drilling well servicing and completions, coiled tubing operations, and well testing. Ideally the supervisor should be certified in both well sen,icing blowout prevention and drilling well control.8

Unfortunately, the curricula in these courses fall short of the optimum needed for a supervisory role. These courses do not adequately address the auxiliary services of coiled tubing or well testing.

The ERCB will be addressing this apparent shortfall with the Petroleum Industry Training Service through the blowout prevention and well control examination and certification committee. Possibly a modification of the existing courses or a new more appropriate course will result.

Both drilling and completions personnel are typically involved in the well planning stare. Several operators now include the service companies and the drilling contractor in the planning stage. This practice helps in running a safe and efficient operation in the field.

Because of the large number of services and associated personnel on location during underbalanced operations, several companies have be,un providing a central command center. Representatives from the key service companies stay in radio contact with their staff, and the well-site supervisor can then efficiently and effectively coordinate all activities.

ERCB REQUIREMENTS

Only one section (Section 8.140) of the Alberta Oil and Gas Conservation regulations covers underbalanced drilling.

Although this section is intended for air drilling, some of what is stated is applicable to an forms of underbalanced drilling. According to Section 8.140, if a well is being drilled with air, the licensee, or operator, shall install and maintain the following (in addition to the required BOP equipment):

• A rotating head that diverts the flow when the well is drilled with air

• A diverter line not less than 50 m long

• A reserve volume of drilling fluid equal to at least 1.5 times the capacity of the hole

• A continuous H2S monitor on the diverter line if the formations may contain H2S

• A continuous ignition device at the end of the diverter line.

The ERCB reviews each new underbalanced drilling application based on site-specific circumstances and focuses on three main aspects of the operation: well control equipment, surface handling of fluids, and supervision. The procedures, equipment, and supervision requirements can vary greatly depending on the conditions expected in the proposed well.

These conditions include the potential pressures expected at surface, the possibility of either sweet or sour gas, and the extent of under-pressure in the reservoir (that is, the reservoir will not support a full column of water or reservoir fluid).

The proposed equipment and procedures must be appropriate for the drilling fluids and well conditions expected. The following key points (applicable to operations worldwide) are addressed for each application:

WELL CONTROL EQUIPMENT

• BOP stack configuration including diverter

• A device installed in the drillstring to prevent flow into the pipe while tripping or making connections; a fire float for air systems

• Drill pipe protection or the installation of blind shear rams if the well contains sour gas

• Kill fluid on site in accordance with Section 8.140 of the regulations.

• Casing integrity and the need for full length cementing of the casing string.

SURFACE HANDLING OF FLUIDS