Underbalanced drilling (UBD) Characteristics of UBD

Underbalanced drilling (UBD)

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 different substances to the liquid phase of the drilling fluid,

such as:

Natural gas

Nitrogen

Air

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.

Characteristics of UBD

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 primarywell-control mechanism. The pressure on the bottom of the well will always be designed to

be higher than the pressure in the formation (Fig. 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. 1b).

Fig. 1a—Pressures in conventional drilling.

Fig. 1b—Pressures in underbalanced drilling.

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. 2). Secondary well control is still provided by the BOPs,

as is the case with conventional drilling operations.

Fig. 2—Open vs. closed circulation systems.

Lowhead drilling

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 H2S, or would cause other issues, if hydrocarbons were produced to surface.

Reasons to consider underbalanced drilling

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 inTable 1.

Table 1-Advantages vs. disadvantages of UBD

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 anywhere from three to five bits. It is normally assumed that penetration rates double when drilling

underbalanced.

Classification system for underbalanced drilling

A classification system developed by the Intl. Assn. of Drilling Contractors (IADC) is helping establish the risks

associated with underbalanced drilled wells (Table 2).

Table 2-Risks Associated With UBD Wells

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 3.

Table 3-Classification System for UBD Techniques

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 UBD

Most reservoirs can be drilled underbalanced, but some cannot, 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 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, the

possible damage mechanisms, and the economic reasons for UBD. All issues must be considered carefully when

choosing whether or not to drill underbalanced.

Table 4-UBD Effects For Reservoir Types

Reservoir selection issues

Appropriate 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 5. Fig.

3 shows this UBD evaluation process as a flow chart.

Table 5-Steps in a Typical UBD Evaluation

Fig. 3—UBD flow chart.

Economic limitations

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, however, is 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.

Reservoir studies

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 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 overbalanced drilling (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.

Underbalanced drilling limitations

There are limitations, as well as advantages, to underbalanced drilling (UBD). Before embarking on a UBD

program, the limitations of the process must be reviewed.

Factors that negatively affect underbalanced drilling

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.

Technical limitations

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 measurement while drilling (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 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.

Surface equipment for UBD operations

Selecting surface equipment is the final step in designing an underbalanced drilling (UBD) operation. The surface

equipment for UBD can be broken down into four categories:

Drilling system

Gas-generation equipment

Well-control equipment

Surface separation equipment.

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 1). 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. outer diameter (OD). This is because of many

factors, including:

The flow rate through the coil

Pressure drop through the tubing

Weight on bit (WOB)

Profile of the well

Maximum pickup weight

Both in-hole and surface equipment

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.

Table 1-Relative Merits of Coiled Tubing Vs. Jointed Pipe

Gas-generation equipment

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. 1 shows a nitrogen-generation system.

Fig. 1—A nitrogen generating system.

A nitrogen generator is 50% efficient. In real terms, if 1,500 ft 2 /min of nitrogen is required, then 3,000 ft 2 /min

of air needs to be pumped into the generator. A full nitrogen system for 1,500 ft 2 /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. 2 shows the nitrogen generation equipment rigged up

on a jackup.

Fig. 2—Offshore nitrogen generating system.

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 worsened

when salt brine systems are used at elevated temperatures (Fig. 3).

Fig. 3—Onshore nitrogen generator and compressors.

Well-control equipment

Jointed-pipe systems

The conventional blowout preventer (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. 4).

Fig. 4—Typical BOP stack-up.

A rotating control-head system and primary flowline with emergency shut down (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 bottomhole assembly (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. 5).

Fig. 5—Typical coiled-tubing stripper assembly.

The reeled systems can then be tripped much faster, and the rig-up is 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. 6). 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. 7).

Fig. 6—Rig-assist snubbing system.

Fig. 7—Push/pull snubbing machine.

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.

Types of rotating diverter

There are currently two types of rotating diverter: active and passive.

Diverter Type Description

Active Rotating

Diverter

The active type uses external hydraulic pressure to activate the sealing mechanism

and increase the sealing pressure as the annular pressure increases

Passive Rotating

Diverter

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. 8). 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.

Fig. 8—Rotating control head.

Rotating BOPs (active systems)

The rotating blowout preventer (RBOP) 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. 9).

Fig. 9—Rotating BOP.

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. 10). The chosen approach depends largely on the expected reservoir fluids.

Fig. 10—Various solids-control and fluid-separation strategies.

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 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 2. 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.

Table 2-Classification of Separators

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. 11 and 12).

Fig. 11—Horizontal separator.

Fig. 12—Vertical separator.

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 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.

Downhole equipment for UBD operations

Successful underbalanced drilling (UBD) requires downhole equipment to provide real-time information to the

surface for monitoring conditions during drilling operations.

Pressure while drilling (PWD) sensors

Pressure while drilling (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 has a few of the following benefits: enhanced

UBD operation, help optimize the drilling process, and increase the operator’s knowledge of the reservoir.

Conventional measurement while drilling (MWD) tools in UBD

The most common technique for transmitting measurement while drilling (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 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, but not limited to:

The mud properties

Drillstring arrangement

Flow rate

Signal strength generated at the tool

Telemetry frequency

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 a number of factors, including:

Well depth

Profile

Liquid-phase fluid

Drillstring/bottomhole assembly (BHA)

Pumping pressure

Flow rates.

Further reductions in borehole pressure are possible with gas lift applications in which N2 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

equivalent circulating density (ECD) monitoring.

Nonreturn valves

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 bottomhole assembly (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.

Deployment valves

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. The result is 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 at conventional tripping

speeds, 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. After this is completed, 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. The valve can also 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 to determine the overall daily

drilling costs.

Reservoir inflow in underbalanced drilling

In underbalanced drilling (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 and minimize the impact to the circulation system or moving out of the UBD window

already established.

Factors influencing reservoir inflow

The rate of reservoir fluid inflow depends, in part, on the drawdown and reservoir rock properties (the differential

pressure between circulating bottomhole pressure (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.

Reservoir inflow performance

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 intent of drilling any well underbalanced is to:

Create conditions that induce the flow of reservoir fluid into the well while drilling

Minimize reservoir damage

Optimize production of reservoir fluid from the well

Characterize the reservoir

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 and flow control matrix as defined by the well control strategy. Where the

surface pressure, production rate, or BHP cannot be maintained within appropriate well control levels or

underbalanced, drilling operations must cease immediately and pre-defined well control actions are to be taken.