Underbalanced Drill ing Senior Project

Underbalanced Drilling Of Horizontal

Gas Well

Obaiyed field case study

Under supervision of/

Eng. Abd El Fatah Sharf

Team members/

1. Abdallah Magdy Darwish

2. EL Sayed Amer Hassan (Eng20072007@yahoo.com)

3. Mossad Mossad Dawood

4. Sandy Mohamed Sherif

5. Mina Naguib

6. Magdy Hamaza Ahmed

Cost - Depth Curve OBA D2 UBD

4160

4210

4260

4310

4360

4410

4460

4510

4560

4610

4660

$0 $500,000 $1,000,000 $1,500,000 $2,000,000 $2,500,000 $3,000,000 $3,500,000 $4,000,000 $4,500,000

Cost in $

Dep

th in

m

Plan Actual

El Sayed Amer Hassan

Team Work

Mina Naguib Magdy Hamza

Abdallah Magdy Darwish

Mossad Mossad Dawood Sandy Mohamed Sherif

Under supervision of/ Eng. Abd-Elfatah Sharaf

We dedicate this book to all the

Egyptians who pay their life for the rise of

this country. These people will be-

forever- in our hearts where no one can

erase them.

I

Acknowledgement

Although we didn't study UBD; But we

challenged the process

We would like to express our deepest gratitude to our advisor

Eng. Abd- El Fatah Sharaf

For supervising this work and for his valuable guidance and

genuine interest in completing this study. We would like to thank our family for their ultimate help and efforts without Allah's blessing and their prayers we would not

be able to finish this work.

We also like to acknowledge our

Prof. Attia M. Attia,

Eng. Sayed RIzek,

Eng. Ahmed El Rayan

Eng. Mohamed Salah

Project Team Work

2012

II

ABSTRACT

Much UBD technology is still considered relatively new, and probably just leaving the Early Adopters stage. The key to success in moving underbalanced drilling up the growth curve lies in a good understanding of the technology, careful planning (including full consideration of the risks), disciplined execution, and effective dissemination of technological information. Otherwise, early adopters can pay dearly for taking up the flag of new technology. Several papers have been published discussing the UBD processes as well as the benefits achieved from this technology. However, few papers have examined the criticality of planning for UBD operations.

We provide a detailed study in how to plan for UBD operations to achieve success in drilling the well. Our case study was brought from BAPETCO Egyptian Company, obaiyed concession, western desert. The study emphasizes formation stability, appropriate technique, well control, minimum formation damage, hydraulic analysis, and guaranteed economic incentives.

Project Team Work

2012

HISTORY OF UNDERBALANCED DRILLING ............................................................................................... 3

WHAT IS UNDERBALANCED DRILLING? ................................................................................................... 4

UNDERBALANCED VERSUS OVERBALANCED .......................................................................................... 6

BENEFITS OF UNDERBALANCED DRILLING .............................................................................................. 8

DISADVANTAGES OF UNDER BALANCED DRILLING: ............................................................................. 13

IMPORTANT LIMITATION FOR UNDERBALANCED DRILLING................................................................. 15

HOW TO DRILL UNDERBALANCE- TYPE OF UNITS? ............................................................................... 16

REFERENCES .......................................................................................................................................... 20

UNDERBALANCED DRILLING TECHNIQUES

GASEOUS DRILLING FLUIDS ................................................................................................................... 23

MIST DRILLING ...................................................................................................................................... 34

FOAM DRILLING .................................................................................................................................... 37

GASIFIED OR AERATED SYSTEMS .......................................................................................................... 43

FLOW DRILLING ..................................................................................................................................... 49

MUD CAP DRILLING ............................................................................................................................... 49

SNUB DRILLING ..................................................................................................................................... 50

CLOSED SYSTEM .................................................................................................................................... 50

REFERENCES .......................................................................................................................................... 51

RESERVOIR CANDIDATES AND OPTUMIM SELECTION

GOOD CANDIDATE INDICATORS FOR UBD ............................................................................................ 54

BAD CANDIDATE INDICATORS FOR UBD ............................................................................................... 55

OPTIMUM SELECTION OF UNDERBALANCED TECHNIQUES.................................................................. 56

GENERAL CONSIDERATION TO SELECT DRILLING FLUID ....................................................................... 59

ECONOMIC STUDY MODEL ................................................................................................................... 74

REFERENCES .......................................................................................................................................... 89

SURFACE EQUIPMENT OF UNDERBALANCED DRILLING

INTRODUCTION ......................................................................................................................... 92

GAS SUPPLY ............................................................................................................................... 92

AIR COMPRESSION SYSTEM ........................................................................................................ 94

IN-LINES FACILITIES .................................................................................................................... 98

SEPARATION SYSTEM ............................................................................................................... 101

PITS & TANKS........................................................................................................................... 104

FLARE SYSTEM ......................................................................................................................... 105

SURFACE MEASUREMENTS ....................................................................................................... 106

FOAM DRILLING ACCESSORIES .................................................................................................. 107

SURFACE EQUIPMENT LAYOUT FOR DIFFERENT UBD TECHNIQUES ............................................. 111

IADC UNDERBALANCED OPERATION COMMITTEE ..................................................................... 114

OBAYED FIELD SITE DRAWINGS & EQUIPMENTS ........................................................................ 116

REFERENCES ............................................................................................................................ 119

DOWNHOLE EQUIPMENT FOR UNDERBALANCED

DRILLING ROTARY DRILL STRING......................................................................................................................... 122

DRILLING BITS ...................................................................................................................................... 125

DRILLING JARS ..................................................................................................................................... 133

STABILIZERS ......................................................................................................................................... 134

REAMERS ............................................................................................................................................. 134

SHOCK SUB .......................................................................................................................................... 135

BOTTOM HOLE ASSEMBLY .................................................................................................................. 135

DOWN HOLE MOTOR .......................................................................................................................... 136

MEASURMENT WHILE DRILLING (MWD) ............................................................................................ 137

ELECTROMAGNETIC MWD .................................................................................................................. 137

ELECTROMAGNETIC MWD .................................................................................................................. 138

PRESSURE WHILE DRILLING (PWD) ..................................................................................................... 139

HEAVY WEIGHT DRILL PIPE ................................................................................................................. 139

FLOAT VALVES ..................................................................................................................................... 140

DOWN HOLE ISOLATION VALVES ........................................................................................................ 143

DRILL PIPE............................................................................................................................................ 144

REFERENCES ........................................................................................................................................ 145

COILED TUBING

INTRODUCTION: .................................................................................................................................. 148

WHAT IS COILED TUBING? .................................................................................................................. 149

FEATURES OF CT TECHNOLOGY: ......................................................................................................... 149

USES OF COILED TUBING IN OIL INDUSTRY:........................................................................................ 150

ADVANTAGES OF COILED TUBING: ..................................................................................................... 151

DISADVANTAGES OF COILED TUBING ................................................................................................. 151

COILED TUBING EQUIPMENT .............................................................................................................. 152

COILED TUBING APPLICATIONS ........................................................................................................... 155

COILED TUBING DRILLING ................................................................................................................... 156

COMPARISON BETWEEN COILED TUBING & JOINTED PIPE ................................................................ 156

REFERENCES ........................................................................................................................................ 166

DIRECTIONAL DRILLING

DIRECTIONAL DRILLING (D.D).............................................................................................................. 168

DIRECTIONAL DRILLING APPLICATIONS .............................................................................................. 172

DEVIATION CONTROL METHODS ........................................................................................................ 180

DIRECTIONAL DRILLING TOOLS AND TECHNIQUES ............................................................................. 181

HORIZONTAL WELLS ............................................................................................................................ 196

HORIZONTAL DRILLING APPLICATIONS .............................................................................................. 196

REFERENCES ........................................................................................................................................ 202

Problems

ANTICIPATED PROBLEMS ......................................................................................................... 204

DIRECTIONAL DRILLING PROBLEMS .......................................................................................... 215

PROBLEMS ENCOUNTERED DURING UNDERBALANCED DRILLING .............................................. 218

PROBLEMS ENCOUNTERED DURING DRILLING OBAYED FIELD .................................................... 224

CORROSION PLAN FOR UB OBAYED FILED ................................................................................. 228

REFERENCES ............................................................................................................................ 233

WELL CONTROL IN UNDERBALANCED DRILLING

WELL CONTROL DEFINITION ..................................................................................................... 236

WELL CONTROL PRINCIPLES...................................................................................................... 237

CAUSES OF PRIMARY CONTROL LOSS ........................................................................................ 237

WARNING INDICATORS OF A KICK ............................................................................................ 239

SHUT IN PROCEDURE ............................................................................................................... 239

WELL KILLING PROCEDURES ..................................................................................................... 241

BLOWOUT PREVENTION (BOP) EQUIPMENT .............................................................................. 244

BLOW OUT PREVENTER EQUIPMENT FOR COILED TUBING DRILLING .......................................... 250

COILED TUBING BOP STACK ARRANGEMENTS ........................................................................... 252

WELL CONTROL FOR UNDERBALANCED DRILLING (UBD) ............................................................ 252

UBD BOP STACK ARRANGEMENT .............................................................................................. 256

BOP SCHEMATIC OF OBAIYED D-2 ............................................................................................ 260

REFERENCES ............................................................................................................................ 261

Completion for underbalanced drilling

COMPLETION OBJECTIVE AND FUNCTIONS................................................................................ 264

VERTICAL OR HIGHLY DEVIATED WELL COMPLETION ................................................................. 266

HORIZONTAL WELL COMPLETION ............................................................................................. 268

UNBERBALANCED WELL COMPLETION ...................................................................................... 270

OBAIYED D2-C/D COMPLETION .............................................................................................. 275

REFERENCES ............................................................................................................................ 280

DIRECT CIRCULATION OF AERATED FLUID

INTRODUCTION ....................................................................................................................... 282

MINIMUM VOLUMETRIC FLOW RATES ...................................................................................... 282

INJECTION PRESSURE AND SELECTION OF COMPRESSOR EQUIPMENT ....................................... 288

COMPRESSOR SELECTION ......................................................................................................... 316

REFERENCES ............................................................................................................................ 320

OBAIYED D-2 WELL ENGINEERING

OVERVIEW OF BADER EL DIN PETROLEUM COMPANY ............................................................... 321

OBAIYED D-2 OVERVIEW .......................................................................................................... 322

DETERMINATION OF THE DERRICK LOAD .................................................................................. 326

SWIVEL SELECTION ................................................................................................................... 327

KELLY SELECTION ..................................................................................................................... 328

HOISTING SYSTEM SELECTION: ................................................................................................. 329

SELECTION OF MUD PUMP ....................................................................................................... 334

SELECTION OF THE WELLHEAD FOR OBAYED D-2 ....................................................................... 341

DESIGN OF DRILL STRING.......................................................................................................... 344

CASING AND TUBING DESIGN ................................................................................................... 360

CEMENT PROGRAM ................................................................................................................. 377

DESIGN OF HORIZONTAL TRAJECTORY ...................................................................................... 392

RECOMMENDED DRILLING ASSEMBLIES: ................................................................................... 406

REFERENCES: ........................................................................................................................... 408

RISK ASSESSMENT OF UNDERBALANCED DRILLING

INTRODUCTION OF RISK ASSESSMENT ...................................................................................... 412

RISK ASSESSMENT .................................................................................................................... 412

RISK MANAGEMENT AND DOWNHOLE PROBLEMS .................................................................... 413

PERSONAL PROTECTIVE EQUIPMENT (PPE) ............................................................................... 415

REFERENCES ............................................................................................................................ 417

CONCLUSION AND RECOMMENDATION ................... 419

1

2

History of Underbalanced

Drilling

What is Underbalanced Drilling?

Underbalanced Versus

Overbalanced

Benefits of underbalanced

drilling

Disadvantages of under balanced

drilling

Important limitation for

underbalanced drilling

How to drill underbalance- type

of units?

References

This chapter introduces the fundamentals of underbalanced drilling operation including the history, consideration, limitations and methods of drilling Underbalanced drilling has been around since the start of the oil exploration. All cable tool drilled wells were drilled underbalanced and most of us have all seen the pictures of blowouts and gushers as an oil reservoir was struck. Until 1895 all wells were drilled underbalanced.

3

History of Underbalanced Drilling

Underbalanced drilling has been around since the start of the oil exploration. All cable tool drilled wells were drilled underbalanced and most of us have all seen the pictures of blowouts and gushers as an oil reservoir was struck. Until 1895 all wells were drilled underbalanced. The introduction of rotary drilling technology in 1895 required fluid circulation, which initially was water. To enhance safety and hole cleaning, mud systems were developed in 1920 and drilling continued overbalanced. As deeper and larger reservoirs were encountered the reservoir damage issues became less of an issue. Until in the 1980s the first underbalanced wells were drilled in the Austin Chalk. This proved to be the introduction to modern underbalanced drilling which started in the early 1990s in Canada. 1284 First cable tool wells drilled in China 1859 - 1895 all wells drilled underbalanced. 1895 Rotary drilling with water. 1920 First mud systems used. 1928 First BOPs used. 1932 First use of gasified fluids to drill 1955 Dusting or air drilling becomes popular. 1988 First high pressure gas well drilled underbalanced in Austin Chalk. 1993 First UBD wells drilled in Canada. 1995 First UBD wells drilled in Germany 1997 First UBD wells drilled offshore. Since 1997, just after the third international underbalanced drilling conference was held, better co-operation between operators internationally was initiated. The first committees were developed as a result of Shell and Mobil requesting more information and co-operation to ensure that offshore wells could be drilled safely underbalanced. In 1998 the IADC took the safety lead in underbalanced drilling and the IADC UBO committee was formed in order to enhance the safety of underbalanced drilling operations. This committee developed the underbalanced classification matrix and continues today to develop safer and more efficient methods and procedures for underbalanced drilling operations. The development of better flow modeling systems and training systems together with international experiences shared between operators has helped to develop underbalanced drilling as one of the primary technologies for enhanced production from depleted fields and reservoir understanding in newly developed fields.

4

What is Underbalanced Drilling?

When the effective circulating downhole pressure of the drilling fluid - which is

equal to the hydrostatic pressure of the fluid column, plus pumps pressure, plus

associated friction pressures - is less than the effective near bore formation pore

Pressure. (Definition)

Underbalanced Drilling P reservoir > P bottom hole = P hydrostatic + P friction + P choke

The well is still controlled by controlling the wellbore pressure, but this pressure is

Maintained to be always below the reservoir pressure. Primary well control is no

Longer an overbalanced barrier of a column of fluid but is replaced by flow

control

Using a combination of hydrostatic pressure, friction pressure and surface choke

Pressure. The BOP stack remains as the secondary well control barrier. It must

be pointed out that a UBD well operates on a single barrier.

The bottom hole circulation pressure is a combination of hydrostatic pressure,

circulation friction losses and surface pressure applied at the choke.

The hydrostatic pressure is considered a passive pressure and is a result of the

fluid density and the density contribution of any drilled cuttings and a small

contribution of any gas in the well.

FIGURE 1:UBD IN THE UNITED STATE

5

The friction Pressure is a dynamic pressure (It changes with pumps on or off) and results from circulating friction of the fluid used. The choke pressure arises from annular back pressure applied at surface. These three pressures are controlled at all times and ensure that flow control is maintained whilst drilling underbalanced. The lower hydrostatic head avoids the build-up of filter cake on the reservoir formation and avoids the invasion of whole mud and drilling solids into the formation. This helps to improve productivity of the wellbore and reduces any pressure related drilling problems Conventionally, wells are drilled overbalanced, which provides the primary well control mechanism. Imposed wellbore pressure arises from three different Mechanisms: 1. Hydrostatic pressure of materials in the wellbore due to the density of the fluid used (mud) and the density contribution of any drilled cuttings (passive). 2. Dynamic pressure from fluid movement due to circulating friction of the fluid used and the relative fluid motion caused by surge/swab of the drill pipe(dynamic). 3. Imposed pressure, with occurs due to the pipe being sealed at surface resulting in an area with pressure differential (e.g., a rotating head or stripper element) (confining or active).

Underbalanced drilling is defined as drilling with the hydrostatic head of the drilling

fluid intentionally designed to be lower than the pressure of the formations being

drilled. The hydrostatic head of the fluid may naturally be less than the formation

pressure or it can be induced. The induced state may be created by adding natural

gas, nitrogen or air to the liquid phase of the drilling fluid. Whether the

underbalanced status is induced or natural, the result may be an influx of formation

fluids which must be circulated from the well and controlled at surface.

Underbalanced drilling in practical terms will result in flow from one or more zones

into the wellbore (this is more likely, however, to be solely from one zone as cross-

flow is likely to result) or where the potential for flow exists.

The lower hydrostatic head avoids the build-up 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 reservoir and reduce related drilling problems.

6

Underbalanced Versus Overbalanced

When comparing underbalanced drilling with conventional drilling it soon

becomes apparent that an influx of formation fluids must be controlled to avoid

well control problems. In underbalanced drilling, the fluids from the well are

returned to a closed system at surface to control the well. With the well flowing,

the BOP system is kept closed while drilling, whereas in comparison to

Conventional drilling fluids are returned to an open system with the well open to

Atmosphere.

FIGURE 2: PERFORMANCE DRILLING DEFINITION

7

Overbalanced Operations "Conventional Drilling"

Mud fluid invasion and the hydrostatic pressure in the well bore can mask

potentially productive zones.

Reservoir damage, especially in horizontal wells, is often difficult or complicated to

remove or clean up once production starts. The lower permeability and porosity

zones may never be properly cleaned up, which can result in large sections of a

well (especially horizontal wells) being unproductive.

Lost circulation and differential sticking can often result in severe drilling problems

and many wells in depleted reservoirs never get to their planned TD.

New productive horizons are often identified when drilling. No damage or minimum

damage is done to the reservoir rocks, including the tighter sections of a well,

resulting in better production.

No losses or differential sticking as the fluid pressure is below the reservoir

pressure.

Figure 3:Conventional and uBD drillig

Conventional Drilling Underbalanced Drilling

8

Benefits of underbalanced drilling

Increased penetration rate.

Increased bit life.

Minimize lost circulation.

Improved formation evaluation.

Reduced formation damage.

Reduced probability of differential sticking.

Earlier production.

Environmental benefits.

Improved safety.

Increased well productivity.

Less need for stimulation treatments.

1-Increased Penetration Rate:

Drilling underbalanced can lead to increased penetration rate. Most references,

describing drilling operations with air or lightened drilling fluids, report penetration

rates which are greater than these for wells drilled overbalanced with

conventional liquid drilling fluids.

In permeable rocks, a positive differential pressure will decrease penetration

because:

o Increases the effective confining stress which.

o Increases the rocks shear strength.

o Therefore increasing shear stress (by drilling UB) increases

penetration rate. And increases the chip hold down effect.

FIGURE 4: CHIP HOLD DOWN EFFECT AS DRILLING FLUID ENTERS THE FRACTURE, THE PRESSURE DIFFERENTIAL ACROSS THE ROCK FRAGMENT DECREASES, RELEASING THE CHIP.

9

2-Increased bit life:

It is often claimed that bit life is increased when lightened fluids are used instead of conventional drilling mud. Drilling underbalanced removes the confinement imposed on the rock by the overbalance pressure. This should decrease the apparent strength of the rock and reduce the work that must be done to drill away a given volume of rock. It is reasonable that this increased Drilling efficiency should increase the amount of hole that can be drilled before the bit reaches a critical wear state therefore:

o Increased vibration with air drilling may actually decrease bearing life. o Bit may drill fewer rotating hours but drill more footage. o The number of bits required to drill an interval will be inversely proportional

to the footage drilled by each bit.

FIGURE 5: BIT AFTER BEING DAMANGED

3-Minimized Lost Circulation

Lost circulation occurs when drilling fluid enters an open formation down hole, rather than returning to the surface. It is possible for drilling fluid to be lost by flow into a very permeable zone. More frequently, lost circulation involves flow into natural fractures that intersect that wellbore or into fractures induced by excessive drilling fluid pressure. Lost circulation can be very costly during conventional drilling. The lost fluid has to be replaced, and the losses have to be mitigated, usually by adding lost circulation material to the mud (to plug off the path by which the fluid is entering the formation), before drilling can safely be

10

resumed. Since there is no physical force driving drilling fluid into the formation if the well is drilled underbalanced, underbalanced drilling effectively prevents a lost circulation problems where If the pressure in the wellbore is less than the formation pressure in the entire open hole section, lost circulation will not occur.

FIGURE 6: LOSS OF CIRCULATION

4-Improved Formation Evaluation

Drilling underbalanced can improve the detection of productive hydrocarbon

zones even identifying zones that might otherwise have been bypassed if the well

had been drilled conventional.

5-Reduces Formation Damage:

Anticipated well productivity is often reduced by regions of impaired permeability, formation damage, adjacent to the wellbore. Formation damage can occur when liquid(s), solid(s) or both enter the formation, during drilling. If the drilling fluid pressure in the wellbore is less than the pore pressure, the physical driving force: causing penetration of material from the drilling fluid is removed. That is not to say that the possibility of formation damage from the drilling fluid is completely removed. In some circumstances, chemical potential differences between drilling and pore fluids could cause filtrate to enter the formation against the pressure gradient. Also, there are instances in which a well, that is drilled nominally underbalanced, experiences transient overbalanced conditions, due to less than perfect control of circulating pressures or possibly due to fluid inflow while the well is not being circulated. In any case, there are many examples of wells drilled underbalanced with higher productivity than adjacent wells drilled conventionally.

11

FIGURE 7:SOLID INVASION INTO A HOMOGENOUS PORE SYSTEM

FIGURE 8: MECHANISM OF SUSPENDED SOLIDS ENTRAINMENT

FIGURE 9: MECHANISM OF SLOIDS ENTRAINMENT IN FRACTURES

12

6-Reduced probability of differential sticking.

In a well drilled conventionally, a filter cake forms on the borehole wall from solids deposited when liquid flows from the drilling mud into permeable zones, due to an overbalance pressure. If the drill string becomes embedded in the filter cake, the pressure differential between the wellbore, And the fluid in the filter cake can act over such a large area that the axial force required moving the string can exceed its tensile capacity. The drill string is then differentially stuck. There will be no filter cake and no pressure acting to "clamp" the drill string if the well is underbalanced. Other mechanisms can cause sticking; underbalanced drilling does not eliminate the possibility of a stuck drill string.

7-Earlier production:

When a well is drilled underbalanced, formation fluids flow into the wellbore from any permeable formation in the open hole section. Penetrating any hydrocarbon bearing formation with adequate drive and permeability will result in an increased hydrocarbon cut in the drilling fluid returning to the surface. With adequate mud logging and drilling records, underbalanced drilling can indicate potentially productive zones, as the well is drilled. Conversely, during conventional drilling, the overbalance pressure prevents formation inflows; hydrocarbon-bearing zones have to be identified from cuttings, core analysis, logging or DSTs.

8-Environmental benefits.

There can be environmental benefits associated with properly managed, underbalanced drilling operations. These depend on the exact drilling technique adopted. With dry, gaseous drilling fluids there is no potentially damaging liquid drilling mud to dispose of after drilling is completed. The chemical used in mist and foam drilling are often benign and biodegradable surfactants that do not pose significant environmental concerns.

FIGURE 10: DIFFERENTIAL STUCK PROBLEM

13

9-Less need for stimulation:

Following conventional drilling operations, wells are often stimulated to increase their productivity. Stimulation include acidizing or surfactant treatment!, to remove formation damage; or hydraulic fracturing can be used to guarantee adequate production in low permeability reservoirs or to bypass damage in higher permeability formations. Reduced formation damage means lower stimulation costs. Therefore: If the formation is not damaged during drilling and completion, stimulation to remove the damage will not be needed.

Disadvantages of under balanced drilling:

1-Increased Operational Complexity space requirements for additional equipment

requires dedicated, knowledgeable personnel

capable of providing onsite coordination of all services

rig crews may be unfamiliar with underbalanced drilling procedures

2-Conventional Mud Pulse MWD is Ineffective when compressible Fluids are used

The alternative electromagnetic MWD data transfer is generally more

expensive and tool availability may be limited.

Wire line wet-connect steering tool result in slower connections and

increased operational complexity.

3-Poorly Managed Multiphase Flow Regimes can Create Drilling Problems:

Insufficient cuttings removal from the wellbore.

Motor can over-speed.

Excessive down hole motor stalling due to low effective fluid injection

rates.

Incorrect fluid mix can create in stationary drilling conditions and

destructive vibrations.

4. Increased Daily Costs Due to Additional Equipment and Personnel

14

TABLE 1: UBD ADVANTAGES VS DISADVANTAGES

Advantages Disadvantages

Decreased formation damage Possible wellbore stability problems

Eliminate risk of differential sticking Increased daily costs

Reduce risk of loss circulation Generally higher risk with more inherent

Problems

Increased ROP More complex tripping operations

Improved bit life Possible increased torque and drag

Reservoir Characterization More complex drilling system

More people required

15

Important limitation for underbalanced drilling

Wellbore stability issues. Deep, high pressure, highly permeable wells

can be problematic due to flow control & safety issues.

Excessive formation water.

High producing zones close to the beginning of the well trajectory will

adversely affect the underbalanced conditions along the borehole.

Not following established design guidelines.

Wells that require hydrostatic fluid or pressure to kill the well during

certain drilling or completion operations.

Slim hole wells with high annulus friction pressures.

Wells that contain significant pressure or lithology variations.

Operators interfering with the UBD experts.

Increased complexity and HSE issues on H2S wells.

Handling and disposal of produced fluids.

Flaring of produced gas.

Erosion and corrosion issues and risks.

Wellbore consolidation.

Increased drilling costs (depending on system used).

Compatibility with conventional MWD systems.

Spontaneous counter current imbibition effects.

Gravity drainage in horizontal wells.

Possible near wellbore mechanical damage.

Discontinuous underbalanced conditions.

Generally higher risk with more inherent problems.

String weight is increased due to reduced buoyancy.

Possible excessive borehole erosion.

Possible increased torque and drag.

16

How to drill underbalance- type of units?

1. Snubbing systems

If tripping is to be conducted underbalanced without a down hole deployment

valve, a snubbing system will have to be installed on top of the rotating control

head system. The current snubbing systems used in underbalanced drilling are

called rig assist snubbing systems. These units need the rig draw works to pull

and run pipe and are designed to deal only with pipe light situations.

A jack with a 10ft stroke is used to push pipe into the hole or to trip pipe out of

the hole. The ability to install a snubbing system below the rig floor allows the rig

floor to be used in the conventional drilling way.

Snubbing with an onshore rig where there is no space under the rig floor to

install a snubbing unit will have to be conducted on the rig floor. In order to

facilitate snubbing, so called push-pull units are installed on the rig floor

FIGURE 11: WELL CONTROL EQUIPMENT FOR SNUBBING

17

Snubbing unit offers better flow capacity, breaking load and rotation capacity and it

is also able to put weight on the downhole tool.

Tripping takes longer because the lengths of pipe have to be screwed together.

Operating this type of unit requires specialized personnel usually consisting of a

head of unit and three or four people per shift

Diameter of the snubbing pipe, usually at least 3 1/2" and sometimes up to

7 5/8" are possible.

Hoisting capacity in the strip phase 340,000 lb

In the snub phase capacity is usually half that of the strip phase due to jack

design.

Circulate at a higher flow rate.

Clean out hard fill and scale that require weight on the tool and rotation.

Spot cement plugs.

Perform some fishing jobs.

FIGURE 12:SCHEMATIC SNUBBING LAYOUT

18

2. Coiled tubing unit

Although coil tubing drilling (CTD) is still considered to be in the early stages

of development, CT has been in use for underbalanced well interventions and

work overs since the 1970s. However, as Figure 19 illustrates, todays CTD

rig with its specially designed mast can be used in any area and in all types of

conditions. In addition to the potential for reduced environmental impact, the

lack of pipe connections in coiled tubing gives it many advantages over

Jointed pipe UBD:

There are no bottom-hole pressure fluctuations due to connections.

Personnel are not required to work directly above the well bore.

The ability to transmit continuous data with the use of electric line

inside the coil.

Continuous injection of gas through the drill string (CT).

Underbalanced tripping is relatively routine and much faster than

with jointed pipe.

Disadvantages of coiled tubing are:

The inability to rotate the string.

Limited pulling or pushing power (surface equipment limitations).

Limited coil life due to fatigue cycles (bending / straightening).

Depth control limitations (depends on equipment selected).

Limitations in reach and hole size (3 6).

Logistical limitations relative to the coil (especially critical offshore).

3-Conventional rig

Two of the advantages of using a conventional rig are its significant mechanical

strength (generally limited by pipe strength) and the capability to rotate the string.

This makes the rig capable of handling operational problems like stuck pipe

(mechanically stuck rather than differentially stuck) and drilling larger hole sizes:

6 8. In addition, only the reservoir section is usually drilled underbalanced.

Therefore, if a conventional rig is used to drill to the top of the reservoir, it is often

cost-effective to continue with jointed pipe operations in UBD mode in the

reservoir.

19

One of the main disadvantages of using conventional rig / jointed pipe in UBD mode

is the fact that fluid circulation has to be interrupted while making connections. This

may lead to undesirable down-hole pressure fluctuations.

On many of the wells using underbalanced techniques there will be a point where a

pipe light situation will exist. This occurs where the forces inside the well-bore

acting to push the string out, is greater than the forces tending to keep it in the well

bore (p primarily the weight of the string .In a UBD operation, designing a down-

hole lubricator into the casing or completion string can be used to the same effect;

by installing a full-opening valve down-hole at a depth where the force due to the

weight of the string is greater than the forces acting to push the string out. The drill

pipe is stripped out (or run in) to just above the valve. The well can then be shut in

at this depth to allow tripping out (or stripping in) to continue in a normal or

conventional manner. To prevent impairment of the reservoir, the well bore below

the down-hole valve must contain only reservoir-induced fluids (no drill fluid) prior to

shutting in.

FIGURE 13:DOWN-HOLE DEPLOYMENT VALVE

20

References

Bieseman, T., Emeh, V., 'An introduction to Underbalanced Drilling',

RKER.95.071

Bourgoyne Jr., AT., et al 'Applied Drilling Engineering' SPE Textbook

Series 1986, ISBN 1-55563-001-4

Stone, C.R. and Cress, L.A.: New Applications for Underbalanced

Drilling Equipment, paper SPE 37679, manuscript under review (1997).

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For Underbalanced Drilling operation

This chapter provides detailed descriptions of the different techniques of underbalanced drilling. The major function of the circulating drilling

fluid in underbalanced drilling is to lift cuttings from the hole. This

aspect of each technique is considered in some detail. Methods for

analyzing hole cleaning and circulating pressures are reviewed. In each

case, the required equipment is described. Any special operating

procedures that may have to be adopted are described, as are any

limitations.

Contents: Gaseous Drilling Fluids

Mist Drilling

Foam drilling

Gasified or aerated Systems

Gasification techniques

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Gaseous Drilling Fluids

This section will refer to the compressed gas phase as air since it is the most

economical and widely used gas in reduced pressure drilling. However, other

gases may be substituted in each of the systems discussed; Specifics to natural

gas, nitrogen or exhaust gas being used are discussed separately.

Characteristics of gaseous drilling:

Fast penetration rates

Longer bit life

Greater footage per bit

Good cement jobs

Better production

Requires minimal water influx

Slugging can occur

Mud rings can occur in the presence of fluid ingress

Relies on annular velocity to remove cuttings from the well

Problems of gaseous drilling:

Maximum Water influx.

Washouts of tool joints.

Corrosion and erosion problems.

Downhole fires with air.

Inefficient in Crooked hole.

FIGURE 1: GASEOUS DRILLING TECHNIQUES

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1. Air Drilling

Drilling with air, nitrogen enriched air, natural gas, liquid nitrogen or other gas

often called dusting since no fluid (Water / Soap) injection means the annular

returns are Dust. It provide a minimum hydrostatic pressure Bottomhole

circulating pressures may be less than 60 psia (400 kPa) at 8000 Ft. (2500

meters) and a maximum rate of penetration.

Air is about 78 percent nitrogen, 21 percent oxygen and contains carbon dioxide,

water vapor and trace of rare gases. Air is the least expensive of gases because

it is only need to be compressed by using compressors to be used in drilling.

1.1. Drilling technique

The "dust" technique is used when drilling dry formations, or where any water influx is slight enough to be absorbed by the air stream.

The temperature of the air injected into the hole should be slightly higher than the temperature at ambient conditions.

As the air travels down the drill string the air is heated to that of the surrounding formation.

When the air passes through the jet nozzles, the air expands and the velocity increases to supersonic flow .This causes the temperature to decrease and cool the bit and the bit bearings.

As the air travels up the annulus, the air is then reheated to the temperature of the surrounding formation. This medium requires significant compressed gas volumes to clean the well with average velocities of over 3,000 ft per minute.

Important notes should be considered in Air drilling:

Since the air has no structural properties to produce transport

characteristics, removal of cuttings is dependent on the annular velocity of

the air. Annular velocities in excess of 1000[m/min] or 3000[ft/min] are

typically employed for cuttings transport.

FIGURE 2: AIR (DUST) OUT-LINE

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Drilling with dry air systems is restricted by water producing formations, unstable wellbores and high formation pressures. When water saturated formations are encountered, the wet drill cuttings stick together and to the pipe walls and will not be carried from the hole by the air velocity. When these cuttings fill the annulus a mud ring will form which stops the flow of air and the pipe will stick.

TABLE 1: DUST DRILLING ADVANTAGES & LIMITATIONS

Dust Drilling Limitations Advantages of Dust Drilling System

Wellbore fluid influxes cannot be handled effectively with Dust drilling

Optimum environment for use with Air Hammers

Influxes will wet cuttings resulting in mud rings in the annulus, restricting hole cleaning.

Least Expensive operations

Switching to Mist or Foam allows continued Air Drilling in the presence of water.

No fluid system to clean up or disposal at the surface

Chance of Down-Hole Fire if Mud Rings are not eliminated

Maximum Penetration Rates.

The problem of down hole fires normally only occur with air drilling where the air is more than 90% of the fluid/air volume.

Extended bit life.

Compression costs with air are US$300/day or more with significant mobilization and demobilization costs

Corrosion problems is obtained than any other technique due to the presence of 21% of oxygen

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1.2. Unloading and Drying the Hole

The method, proven in actual field operations to unload the hole of fluid, dry the

hole and start air dust drilling is given below:

1. Run the drill string, complete with desired drilling bottom hole assembly and

bit, to bottom.

2. Start mud pump and run as slow as possible. Pump fluid at a rate of 1

to 2 barrels per minute. This may necessitate crippling the pump to get

this rate. This is done to reduce fluid friction pressures to a minimum

and pump at a minimum standpipe pressure for circulation. Standard fluid

hydraulic calculations will indicate what the standpipe pressure should be at

1 to 2 BPM.

3. Bring one compressor and booster on line. This will aerate the fluid being

pumped down the ho1e. About 100 to 150 SCFM per barrel of fluid should

be sufficient for aeration. If too much air volume is being used, the

standpipe pressure will exceed the pressure rating of the compressor and/or

booster. Therefore, slow the compressor down until air is being injected and

mixed with the fluid going down hole. Also, the mist pump and soap injection

pump should be injecting water and soap at a rate of about 12 bbl/hr and

3gal/hr, respectively. The soap will tie the fluid and air together and provide

better aeration properties.

4. As the annular fluid column is lightened, the standpipe pressure will drop

and additional compressors or air volume can be added to further lighten

the fluid column and unload the hole. The aeration procedure is far

superior when compared to the slug method of unloading the hole. The

slug method is accomplished by pumping alternate slugs of water and air

down the hole until air can be used continuously. Air is first injected up to an

arbitrary maximum pressure, then water is injected to lower the pressure

back to some arbitrary minimum pressure. This procedure is repeated until

air can be injected continuously. The aeration procedure requires less time,

does not because undue surging of the hole due to heading, does not cut

out pit walls because surges are eliminated and can be done generally at

lower operating pressures.

5. When the hole is unloaded, the mist pump and soap injection pump should

remain in operation. This provides a mist (1.5 BW/hr. per inch of hole

diameter and 0.5 to 4 gal. soap/hr) which can clean the hole of sloughing

formations.

6. At this point drilling, using air mist can commence. Drill 20 to 100 feet to

allow any sloughing hole to be cleaned up.

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7. After the hole has stabilized (no sloughing), stop drilling and blow the hole

with air mist to clean the hole of drill cuttings. About 15 to 20 minutes is

sufficient or until the air mist is clean. Clean air mist is usually a fine spray

and white in color.

8. When the hole is clean, stop air misting, break off the Kelly and pour 10 to

20 gallons of soap followed by 20 to 4 barrels of water directly down the drill

pipe. Do not mix soap and water in mist pump and inject it that way. Pouring

the soap and water directly down the drill pipe has proven to be a better

procedure and gives a better soap slug and a greater drying effect.

9. Put the Kelly back on and set the bit on bottom. Since the hole is now full of

air, the soap and water will run to bottom. A proper soap sweep cannot be

achieved unless it is mixed with air and pumped up the annulus. This cannot

be done if the drill bit is above the soap and water.

10. With the bit directly on bottom, start air down the hole. Pump straight air at

normal drilling volumes until the soap sweep comes to the surface. The

soap will appear at the end of the blooie line and look like shaving cream.

11. Continue to blow the hole with air for about 0.5 to 1 hour.

12. Start drilling and the hole should dust after 5 to 10 feet have been drilled.

Sometimes as much as 60 to 90 feet are required for dust to appear at the

surface.

2.Natural Gas Drilling

If a source of high-pressure natural gas at the correct volumes is available,

drilling with natural gas is a very good option. The use of air hammers with gas

drilling is another option that can be used to increase ROP. This is an option

used in tight gas reservoirs.

A flow regulator and a pressure regulator are

normally used to control the amount of gas

injected during the drilling process. Natural

gas is also non-toxic and non-corrosive if

sweetened correctly. Natural gas has

greater solubility in hydrocarbons when

compared to nitrogen, which may result in

the potential for greater disengagement

problems and asphalting precipitation.

FIGURE 3: UBD LOCATION WITH NATURAL GAS

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The most efficient use of natural gas is normally through annular injection. The

use of natural gas through the drillstring is not recommended, as gas will have to

be vented every time a connection needs to be made although this can be done

safely. The use of natural gas injection through a coiled tubing system is also not

recommended, as a pinhole in the coil could not be isolated and gas maybe

released to form an explosive mixture inside the wraps of the coiled tubing reel.

Using natural gas will prevent the formation of a flammable gas mixture

downhole when a hydrocarbon producing zone is penetrated. This inherently

higher potential for surface fires requires few changes in operating procedures

from those used in dry air drilling.

3.Nitrogen drilling

a. Cryogenic Nitrogen Nitrogen is by far the most common gas that is currently being used to lighten

the circulating fluid column in underbalanced drilling operations.

Properties of Nitrogen are listed below;

Nitrogen is a colorless, odorless and tasteless gas that makes up four fifths of the earths atmosphere.

Nitrogen is non-toxic, non-flammable and noncorrosive. It has very low solubility in water and hydrocarbons, and is compatible

with virtually any fluid used in drilling operations. Nitrogen does not tend to form hydrate complexes or emulsions. Nitrogen forms a major part of our atmosphere in the fact that the

atmosphere comprises of: 78.03 % Nitrogen.

Cryogenic nitrogen definition

Cryogenic nitrogen is frozen liquid nitrogen. It is the byproduct of oxygen

manufacture where air is compressed and cooled and then compressed again

until the nitrogen appears as a clear liquid at -320F (-160C). A gallon of liquid

nitrogen produces 93.12 scf of gas. One Liter of liquid nitrogen produces 0.698

sm3 of gas. The nitrogen produced is 99.9 percent pure and contains no

oxygen. The field of science that deals with the technology of handling liquids

colder than -187F is called cryogenics

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Cryogenic nitrogen production

Cryogenic nitrogen is produced by extraction from the air through fractional

distillation. In this process the air is liquefied and the liquid is then separated

though the following factors;

Liquid air boils at -317F Liquid nitrogen boils at -320F Liquid oxygen boils at -297F.

Oxygen starts to evaporate leaving Nitrogen rich liquid. By repeating the boiling

and condensing processes high purity of liquid nitrogen up to 99.98 % can be

obtained.

Procedure for Converting from Liquid Volume into gas volume.

1 gallon liquid nitrogen produces 93.12 ft3 of N2 at SCP. 1 m3 of N2 liquid produces 698 m3 of gas at SCP. 1 gal of liquid nitrogen is 93.12 ft3 at STC. 1 gal of liquid nitrogen is 0.1333 ft3. 1 liter of liquid nitrogen is 698 litres of gas at STC.

Cost of cryogenic nitrogen

World-wide is 1-3 US $/gal or 0.10 US $/scf. In Canada is 0.02 US $/scf. In South America is 1.00 US $/m3.

FIGURE 4: CRYOGENIC NITROGEN-PUMPING EQUIPMENT

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3.2 Membrane Nitrogen Nitrogen gas is generated by introducing compressed air into hollow membrane

fibers, which preferentially separate oxygen and other rich gases from the air

leaving high purity nitrogen at around 95%. The remaining 5% is normally

oxygen.

Membrane process procedure in field use

The membrane is a small, long, and hollow straw. Air is fed into one end of each

membrane straw. Oxygen and water vapor quickly penetrate the membrane and

escape, which leaves only nitrogen to exit from the end of the membrane.

Each membrane looks similar to white horsehair. Thousands of membranes are

placed inside a stainless steel operating bundle, or canister, about 14 in. (35 cm)

in diameter and 5 ft (1.5 m) long. A number of the bundles are paralleled together

to make a nitrogen unit. Warm, filtered air is pumped into the bundles at 350 psi

(2,400 kPa) and is recovered as nitrogen at the discharge end at 300 psi (2,000

kPa). The efficiency of the system is about 50 percent, so only about half of the

input volume of air is recovered as nitrogen.

The nitrogen is then pressured with an air compressor booster and sent to the

rig system

FIGURE 5: CRYOGENIC NITROGEN

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Nitrogen Production (NPU) Equipment Configuration

The NPU receives compressed air from one or more primary compressors at

pressures ranging from 100 to 350 psig. The product nitrogen is pumped, with

about a 20-40 psig pressure drop, to the suction of a booster compressor where

its pressure is increased to that required for injection into the drillstring.

NPUs have three major components: an air filtration system, an array of air

separation modules, and a control panel.

The air filtration system usually consists of a scrubber, coalescing filler, and a particulate filter. Some NPUs also include an activated carbon bed filter and possibly a refrigerated air dryer. The activated carbon bed filter removes aerosol-sized and smaller oil droplets down to a concentration of a few parts per billion. The refrigerated air dryer reduces the relative humidity into the carbon bed to improve oil droplet filtration.

The arrays of hollow fiber modules are manifold together to accept the clean compressed air feed and to collect and deliver the nitrogen product. The oxygen and water vapor permeate stream is also collected from each membrane module and piped at near atmospheric pressure to the outside of the NPU skid, where it can quickly and harmlessly dissipate into the atmosphere.

The control panel on the NPU allows monitoring and control of the operation. Control panel design and function vary greatly depending on the manufacturer. Some panels measure flow rates, temperatures, purity, and pressure drops across the NPU precisely, yet others only provide simple output of flow rate and nitrogen purity.

FIGURE 6: NITROGEN GENERATING UNIT (NGU)

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2. Exhaust Gas

Exhaust gas is a unique method of taking the oxygen out of air and using the

process to run compressors, By using a diesel engine to run the compressors

and produce the exhaust gas, which is high in nitrogen, the cost of gas

compression is shared with the cost of producing nitrogen, which makes both

less expensive

A potentially very attractive source of gas is the waste gas stream from self-

contained propane units or diesel fired rig engines themselves. However, when

using diesel fired engines, the combustion process is relatively inefficient and the

flue gas can contain 10 - 15% oxygen plus corrosive gases such as CO2 and

NO2 which may react adversely with produced hydrocarbons, thus accelerating

the corrosion process.

Hole cleaning in gaseous drilling

Optimizing hydraulics with gasses is primarily concerned with hole cleaning -

getting the cuttings that are generated by the bit out of the hole. With gas,

rheological properties have very little to do with hole cleaning. Hole cleaning with

gasses is almost entirely dependent on the annular velocity.

Drag and gravitational force: The lifting power of an air drilling system is

proportional to the circulating density, and to the square of the velocity. The

density, and thus the suspension properties, of an air stream is much lower than

a conventional mud system. Therefore, the annular velocity is the primary factor

in transporting the cuttings to the surface.

FIGURE 7: FLOW PATH OF PROPANE EXHAUST GAS

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VIP notes

Compressibility of air (or gas) complicates matters. Frictional pressure increases downhole pressure - decreases

velocity downhole. Suspended cuttings increase the density of the air, increasing

downhole pressure.

Temperature has an effect on volumetric flow rate. We must pump at a velocity high enough to remove the cuttings,

but not too high where we waste energy.

Hole Cleaning Criteria: there are major three properties controls the hole

cleaning criteria

Terminal Velocity Criteria. Minimum Energy Criteria. Minimum BHP Criteria.

Erosion of gaseous drilling

A high annular velocity may cause erosion in soft formations. If the use of an air

drilling technique causes erosion of the well-bore, the addition of a stabilizing

agent or changing air drilling techniques may be required to minimize this

problem.

Erosion of the drill string can also be caused by the high annular velocities and

temperatures generated when steam zones are encountered. Some people

estimate that the velocity may exceed 10,000 ft/min in the annulus. The injection

of barrier type chemicals will inhibit this type off erosion

Corrosion of gaseous drilling

Corrosion should be considered before beginning the use of an air drilling

technique. When drilling through formations with acid contamination (CO2 and

H2S), the problem could be a lot worse. Mixtures or hydrogen peroxide (H2O2)

and caustic soda (NaOH) can be used to solubilize and precipitate the H2S

contamination at the surface. An organic, phosphate, scale inhibitor can prevent

the deposition of alkaline earth metal scale on the drill string.

FIGURE 8: DUSTING BLOOIE LINE

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Mist Drilling Mist drilling is a modification of dry air drilling that is utilized when water producing zones are encountered. Like dry air drilling, this system relies on the annular velocity of the air for cuttings transport out of the hole. In mist drilling, a small quantity of water containing foaming agent is injected into the gas stream at the surface. This produces an air continuous system, with the water mist being carried in the air. Foaming agent concentrations in the water typically range from 0.10% to 0.25% by volume in the water. The foaming agent reduces the interfacial tension of the water and drill cuttings in the hole and allows small water/drill cutting droplets to be dispersed as a fine mist in the returning air stream. This allows the cuttings and water to be removed from the hole without the Formation of mud rings and bit balling. The air mist drilling system provides comparable penetration and footage per bit rates to dry gas drilling, with the added benefit of being able to handle wet formations. Costs of air mist drilling are slightly higher than those encountered with dry gas drilling since foaming agent and corrosion inhibitor are needed.

When should you use mist drilling? Mist Drilling is normally used when formations begin to produce small

amounts of water (10 to 100 bbls per hour) during air/gas drilling operations.

Mist drilling should only use in special applications since hole cleaning is

even more difficult with mist drilling system when compared with air drilling.

.

FIGURE 9: MIST DRILLING OPERATION

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CHARACTERISTICS OF MIST-DRILLING

Air is the continuous phase and the liquid consists of discontinuous

droplets

Similar to air drilling but with addition of liquid

Relies on annular velocity to remove cuttings from the well

Reduces formation of mud rings

High volumes required (30%-40% more than dry air drilling)

Fluid or foam injection rates less than30 [bbl/min] or 100[l/min].

Liquid volume fraction LVF < 0.025

Pressures generally higher than dry air drilling

Incorrect air/gas-liquid ratio leads to slugging, with attendant pressure

Increase.

Can perform simplified calculations by including water mist as drill cuttings

and modify the ROP to account for the equivalent weight being lifted.

The mist particles travel at a slightly different velocity than the air because

of slip.

Advantages of Mist Drilling Gas or air volumes are increased and a mist pump skid is used to inject small

quantities of water and a foaming agent solution. This solution entraps the

water Influx and enables the air phase to lift the cuttings and influx to surface.

Higher ROP than with conventional mud

Enables drilling to proceed while producing fluids.

Improves Hole Cleaning capacity

Reduces risk of downhole fires.

Eliminates need for Nitrogen

Mist Drilling Limitations

Slower penetration rate than Dust drilling due to increased annular hydrostatic pressure.

ROP = 30 50% less than Dusting Limited tolerance to water influx High amounts of Water influx typically make Mist Drilling uneconomical. When large liquid influxes are encountered; options :

Hole Cleaning of mist drilling

Switching to a mist drilling technique requires an increase of at least 30% in the air volume.

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The additional volume is needed to overcome higher frictional losses caused by: wet cuttings adhering to the drill string and hole, higher slip

velocities of larger wet cuttings, and transportation of the heavier wet

air column.

The mud is injected with the air stream to disperse the cuttings and inhibit them from adhering to the drill string and hole.

Although injection pressure of 100 to 200 psig are normally enough for dust drilling, pressures exceeding 350 psig can be encountered while

mist drilling.

Pressures of 1250 psig. may be required when large amounts of fluids are present in the annulus.

The rate of fluid intrusion will dictate the amount of air and fluid that must be injected to efficiently clean the hole.

Formation fluid entries of up to 100 bbl/hr have been successfully mist drilled

Corrosion Control Chemical treatment is needed to minimize corrosion caused by the

additional fluid and air.

Basic corrosion control is provided by maintaining the pH of the mud system above 10.5, and treating any hardness or carbonates with the

appropriate chemical.

Hydrogen sulfide and carbonate scale are treated in much the same way as in a conventional mud system.

Corrosion coupons should be run in the saver and crossover sub to

monitor the type and rate of corrosion.

If H2S is encountered, the first line of protection is to maintain the pH at or above 11.

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Foam Drilling Foam is like shaving cream, not like soap suds. Very dry foam will persist for

many hours like the one in this reserve pit. Foam is dry because all the water is

bound up. In wet foam more water is flee like in soap suds.

FIGURE 10:FOAM IS RELATIVELY NEW FLUID TO THE DRILLING INDUSTRY.

.

If more liquid and a surfactant are added to the fluid, stable foam is generated.

Stable foam used for drilling has a texture not unlike shaving foam. It is a

particularly good drilling fluid with a high carrying capacity and a low density. One

of the problems encountered with the conventional foam systems is that stable

foam is as it sounds. The foam remains stable even when it returns to the surface

and this can cause problems on a rig if the foam cannot be broken down fast

enough. In the old foam systems, the amount of defoamer had to be tested

carefully so that the foam was broken down before any fluid left the separators. In

closed circulation drilling systems stable foam could cause particular problems

with carry over. The recently developed stable foam systems are simpler to break

and the liquid can also be re-foamed so that less foaming agent is required and a

closed circulation system can be used. These systems, in general, rely on either

a chemical method, of breaking and making the foam or the utilization of an

increase and decrease of pH, to make and break the foam.

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The foam quality

The amount of gas in the fluid at any point, measured by volume, can be

expressed as foam quality or as fluid ratio. Ratio R (% by volume of gas) is the

ratio of gas to liquid unit under existing conditions of pressure and temperature. A

good rule of thumb for a gasified fluid is to try to maintain the ratio through the

system at 5:1 to 40:1 (i.e., 80 %< foam quality < 97.5 %).

Drilling with foam has some appeal due to the fact that foam has some attractive

qualities and properties with respect to the very low hydrostatic densities, which

can be generated with foam systems. Foam has good rheology and excellent

cutting transport properties.

The fact that foam has some natural inherent viscosity as well as fluid loss

control properties, which may inhibit fluid losses, makes foam a very attractive

drilling medium. During connections and trips, the foam remains stable and

provides a more stable bottom hole pressure.

Gas phase percent by volume Expressed as %, whole number or Decimal

equivalent (e.g. 75, 75%, or 0.75)

0-55% Aerated Fluid

55%-94% Foam

94%-99.9% Mist

100% Gas/Air

Factors Effecting Foam Quality Pressure.

Depth.

Gas content.

Liquid content.

Maintaining Foam Quality

Gas and liquid injection rates.

Back-pressure on the system.

Measurement.

Calculation (computer models).

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Adding surfactant to a fluid and mixing the fluid system with a gas generates

foam.

Foam used for drilling has a texture not unlike shaving foam. It is a particularly

good drilling fluid with a high carrying capacity and a low density. One of the

problems encountered with the conventional foam systems is that foam does

what it says on the tin. It remains stable.

Characteristics of foam-drilling

Extra fluid in the system reduces the influence of formation water

Very high carrying capacity

Reduced pump rates due to improved cuttings transport

Stable foam reduces slugging tendencies of the wellbore

The stable foam can withstand limited circulation stoppages without

affecting the cuttings removal or ECD to any significant degree

Improved surface control and more stable downhole environment

The breaking down of the foam at surface needs to be addressed at

the design stage

More increased surface equipment required

TABLE 2: VOLUME PERCENT BETWEEN MIST , FOAM AND AIRATED LIQUEDS

Gas volume percentage Name

99.99 96% Mist

96% - 55% Foam

0 55% Gasified Liquid

Guidelines for Foam Drilling

Liquid injection volume 16 80 gpm

Soap injection volume 0.3 to 1.0% by weight 0.05 0.5 gpm

Gas injection volume 300 1000 scft/min

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The Pattern of Foam

Classic foam has a regular geometric shape -that of a 12 sided polygon because

it is the most efficient shape. In a plane two dimensional view, this would be

hexagons. Once the foam is in motion, the figures are distorted by friction.

Classic static foam pattern on the left.

Foam in flow probably looks more like the one on the right.

FIGURE 11: DIFFERENT FLOW PATTERN

Advantages of Foam Drilling

Foam has excellent cuttings carrying capacity.

Lower Air Volume requirements can mean less Air Compression

equipment required than Dust or Mist drilling.

FOAM GASEATION

Emulsion. Mixture.

Hard to Separate Separates easily.

NO Pressure Surges. Heading and pressure surges.

Huge lifting capacity. Normal lifting capacity.

Plugs lost circulation and reduces

head.

Reduces lost circulation by reducing

head.

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During connections (break in circulation) the cuttings will remain

suspended in the annulus.

Holding Back Pressure on Annulus can help reduce water influx and/or

maintain hole wall stability

Higher viscosity aids hole cleaning with lower annular velocity

At the bottom, annular velocities are designed for 100 to 300 feet per

minute (double that for directional wells above 300)

Penetration rate is still significantly higher than with mud but not as high as

with air .

The higher annular pressures may help reduce mechanical wellbore

instability and reduce production rates

Lower annular velocities may reduce erosion of the borehole wall and drill

string

No damage to formation

Continuous Drill Stem test

Controllable BHP

No lost circulation

No differential sticking.

Best for large holes

The Main Reasons for UB Drilling with Foam

1. Stops lost circulation.

2. Improve drilling rate.

3. Protects the reservoir.

4. Avoid differential sticking.

5. Hole cleaning with low fluid volume.

Lost Circulation with Foam

Reduced the mud density no junk.

Foam plugs lost zones.

The Foam bubbles are lost zone plugging agents

Improve Drilling Rate

Low bottom hole pressure increases drilling rate.

For hard rock, the new air hammer works with foam.

Protect Reservoir

No formation damage with no influx into the well bore.

Minimal pressure surges.

Controllable pressures.

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Limitations for Foam Drilling Surface requirements (pits) for Foam can become a problem.

Large pits have to be built to contain the Foam and allow time for settling.

Chemical cost to break down Foam can become expensive.

Large influx of Fluids can break down Foam and thus reduce hole

cleaning.

Foam is a very corrosive environment

Need to pay attention to corrosion inhibitors

Temperature will significantly affect the effectiveness of corrosion

inhibitors.

Large quantities of foam can accumulate at the surface while drilling

Foam is a complicated system and requires computer modeling in order to

properly design the foam in the wellbore

As the quality of the foam decreases, the viscosity of the foam will

decrease

Foam quality changes with pressure and is not a constant in the wellbore

As the pressure increases, the foam quality decreases

Theoretical Foam Types

Stable Foam: 1-2% Surfactant.

Stiff Foam: 1% Surfactant

General Foam Types

Stable foam

Foaming agent

Polymer

Stiff foam

Polymer

Bentonite

pH sensitive foam (amphoteric)

Transform

Foam

Stiff

PH Sensitive

Stable

FIGURE 12: FOAM TYPES

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Gasified or aerated Systems The next system after a foam system is a gasified fluid system, which is used to control slightly higher pressures. In these systems, a liquid is gasified to reduce the density.

Characteristics of gasified-mud systems Gasified liquids are often called aerated fluids Extra fluid in the system will almost eliminate the influence of formation

fluid Unless incompatibilities Occur The mud properties can easily be identified prior to commencing the

operation Generally, less gas is required Slugging of the gas and fluid must be managed correctly Increased surface equipment will be required to store & clean the base

fluid Velocities, especially at surface, will be lower, reducing wear & erosion

both downhole and to the surface equipment. Effective densities of gasified liquids usually range from 4 to 7 ppg Used primarily to avoid or minimize lost circulation The increased ROP will generally not pay for the increased cost Also used today to drill underbalanced and minimize formation damage in

horizontal wells Underbalanced is usually on the order of 250 to 500 psi Less problem with mechanical wellbore stability Reduces formation fluid inflow rates Can be used to drill unconsolidated formations

If a foam system is too light for the well, a gasified system can be used. In these. Systems, liquid is gasified to reduce the density. There are a number of methods that can be used to gasify a liquid system and these methods are discussed within the injection systems section. The use of gas and liquid, as a circulation system in a well, complicates the hydraulics program. The ratio of gas and liquid must be carefully calculated to ensure that a stable circulation system is used. If too much gas is used, slugging will occur. If not enough gas is used, the required bottom hole pressure will be exceeded and the well will become overbalanced

The injection of air into drilling mud creates bubbles in the mud and, because of the surface tension properties of the bubbles relative to the properties of rock and drilling mud, the bubbles tend to fill in the fracture or pore openings in the borehole wall as the aerated mud attempts to flow to the thief fractures and pores his bubble blockage restricts the flow of the drilling mud into these lost circulation sections and thereby allows the drilling operations to progress safely. Aerated fluids have been used to avoid lost circulation in shallow water well drilling, geotechnical drilling, mining drilling, and in deep oil and natural gas recovery drilling operations.

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When drilling with aerated fluid systems it should be realized that these are the most corrosive of all reduced pressure drilling methods. However, with proper selection of supply water, proper pH control and the proper utilization of technologically advanced corrosion inhibitors, aerated fluid systems are successfully used worldwide. Aerated fluids are well suited for highly unstable formations where loss of circulation is a concern. Aerated fluids also provide the greatest tolerance to fluid influx of any reduced pressure drilling system. Costs involved with aerated fluid drilling are primarily related to the composition of the drilling fluid being utilized and corrosion inhibition. Any liquid with injected air, N2, natural gas, or CO2 Liquid is the continuous phase since liquid volume fraction (LVF) > 0.25 at

surface

The gas is compressed at the bottom of the hole and expands as it goes up. It may change the phase and convert into a mist if there is enough air and it is allowed to expand. The only thing that holds the gas to the mud is mud viscosity, the upward velocity of the mud and gas, and the size of the bubbles The gaseated system is a mixture that will separate into gas and fluid

Gasification techniques

We can divide UBD techniques into four categories;

Drillpipe injection Parasite string injection Annular injection (through parasitic liner) Jet-sub Application

FIGURE 13: DIFFERENT TECHNIQUES OF UBD

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1. Drill pipe injection

Drill string injection is the first and simplest method of gas injection into the

circulation system. Compressed gas is injected at the standpipe manifold where

it mixes with the drilling fluid.

The main advantage of drill string injection is that no special downhole

equipment is required in the well. The use of reliable non-return valves is

required to prevent flow up the drill pipe. The gas rates used when drilling with

drill pipe injection system are normally lower than with annular gas lift, and low

bottom hole pressures can be achieved using this system.

The disadvantages of this system include the need to stop pumping and the

bleeding of any remaining trapped pressure in the drill string every time a

connection is made. This results in an increase in bottom hole pressure. It may

then be difficult to obtain a stable system and avoid pressure spikes at the

reservoir when using drill pipe injection. One alternative is to connect the MWD

back to surface using an electric cable. This technique has previously been used

very successfully with coiled tubing as the drill string. If drill pipe is to be used,

wet connects can be utilized; however, the additional time consumed using this

technique can be limiting.

FIGURE 14: DRILLPIPE INJECTION TECHNIQUE

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2. Parasite string injection

The primary problem with aerated fluid systems is that they are unstable. In

foam, the foaming agent and other additives bind the gas-liquid mixture together.

In aerated systems, there is no agent binding the gas-liquid mixture together.

In worst case, there will be pressure surges during drilling and during

connections and trips. Pressure surges can destabilize the wellbore and cause

underbalanced drilling to periodically go overbalanced. During connections and

while tripping, aerated fluids will lose its gas and go flat.

There are techniques, such as adding more gas before connections, which help

reduce the ensuing pressure surge.

The use of a small parasite string strapped to the outside of the casing for gas

injection is really only used in vertical wells. For redundancy reasons, two 1 or

2 coiled tubing strings are normally strapped to the casing string above the

reservoir as the casing is run in. Gas is pumped down the parasite string and

injected onto the drilling annulus. The installation of a production casing string

and the running of the two parasite strings makes this a complicated operation.

Wellhead modification is normally required to provide surface connections to the

parasite strings. This system is not recommended for deviated wells as the

parasite string is easily ripped off with the casing on the low side of the hole.

However, the principles of operation and the advantages of the system remain

the same as with annular injection.

FIGURE 15: PARASITE STRING INJECTION TECHNIQUE

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3. Annula