مشروع التخرج Underbalanced Drilling - Copy

Underbalanced Drilling 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 3. Mossad Mossad Dawood 4. Sandy Mohamed Sherif 5. Mina Naguib 6. Magdy Hamaza Ahmed

([email protected])

Team Work

Under supervision of/ Eng. Abd-Elfatah Sharaf

Abdallah Magdy Darwish

El Sayed Amer Hassan

Sandy Mohamed Sherif

Mossad Mossad Dawood

Mina Naguib

Magdy Hamza

We dedicate this book to all the Egyptians who pay their life for the rise of this country. These people will beforever- in our hearts where no one can erase them.

‫والتحسبن الذين قتلوا فى سبيل‬ ‫اهلل امواتا بل احياء عند ربهم‬ ‫يرزقون‬

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

M

uch 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

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.

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

2

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 1980’s 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 1990’s 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 BOP’s 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.

3

FIGURE 1:UBD IN THE UNITED S TATE

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.

4

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 crossflow 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.

5

FIGURE 2: PERFORMANCE DRILLING D EFINITION

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.

6

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.

Conventional Drilling

Underbalanced Drilling

Figure 3:Conventional and uBD drillig

7

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 .

8

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 o o

Increased vibration with air drilling may actually decrease bearing life. Bit may drill fewer rotating hours but drill more footage. 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

9

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

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.

10

FIGURE 7: SOLID INVASION INTO A HOMOGENOUS PORE SYSTEM

FIGURE 8: MECHANISM OF SUSPENDED SOLIDS ENTRAINMENT

11 FIGURE 9: M ECHANISM OF SLOIDS ENTRAINMENT IN FRACTURES

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.

FIGURE 10: DIFFERENTIAL STUCK PROBLEM

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.

12

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

13

TABLE 1: UBD ADVANTAGES VS DISADVANTAGES

Advantages

Disadvantages

Decreased formation damage

Possible wellbore stability problems

Eliminate risk of differential sticking

Increased daily costs Generally higher risk with more inherent

Reduce risk of loss circulation Problems Increased ROP

More complex tripping operations

Improved bit life

Possible increased torque and drag

Reservoir Characterization

More complex drilling system More people required

14

Important limitation for underbalanced drilling                       

15

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.

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

16

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.

17

FIGURE 12: SCHEMATIC SNUBBING LAYOUT

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 1970’s. However, as Figure 19 illustrates, today’s 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 (3¾ – 6¼).  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: 6¼” – 8½”. 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.

18

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 “downhole 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:D OWN - HOLE DEPLOYMENT VALVE

19

References  Bieseman, T., RKER.95.071

Emeh, V., 'An introduction to Underbalanced Drilling',

 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).

20

21 Underbalanced drilling techniques

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

Underbalanced Drilling techniques

For Underbalanced Drilling operation

Gasified or aerated Systems Gasification techniques

22

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 .

Underbalanced drilling techniques

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.

23 FIGURE 1: GASEOUS DRILLING TECHNIQUES

1. Air Drilling

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 FIGURE 2: AIR (DUST) OUT-LINE 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.


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.

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.

24

 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. T ABLE 1: DUST DRILLING ADVANTAGES & LIMITATIONS


Dust Drilling Limitations

 Wellbore fluid influxes cannot be handled effectively with Dust drilling  Influxes will wet cuttings resulting in mud rings in the annulus, restricting hole cleaning.  Switching to Mist or Foam allows continued Air Drilling in the presence of water.  Chance of Down-Hole Fire if Mud Rings are not eliminated  The problem of down hole fires normally only occur with air drilling where the air is more than 90% of the fluid/air volume.  Compression costs with air are US$300/day or more with significant mobilization and demobilization costs

25

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

Advantages of Dust Drilling System  Optimum environment for use with Air Hammers

 Least Expensive operations

 No fluid system to clean up or disposal at the surface

 Maximum Penetration Rates.

 Extended bit life.

1.2.

Unloading and Drying the Hole

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 1½ 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 1½ 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.


The method, proven in actual field operations to unload the hole of fluid, dry the hole and start air dust drilling is given below:

26


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.

27 FIGURE 3: UBD LOCATION WITH N ATURAL G AS

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.

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.


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.

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 -320°F (-160°C). 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 -187°F is called cryogenics

28

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 -317°F  Liquid nitrogen boils at -320°F  Liquid oxygen boils at -297°F.


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.

29

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: C RYOGENIC NITROGEN -PUMPING EQUIPMENT

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

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


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.

FIGURE 5: CRYOGENIC NITROGEN

30

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.


NPU’s 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 NPU’s 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: N ITROGEN GENERATING UNIT (NGU)

31

2. Exhaust Gas

A potentially very attractive source of gas is the waste gas stream from selfcontained 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.

FIGURE 7: FLOW PATH OF PROPANE 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

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.

32

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 (CO 2 and H2S), the problem could be a lot worse. Mixtures or hydrogen peroxide (H 2O2) and caustic soda (NaOH) can be used to solubilize and precipitate the H 2S contamination at the surface. An organic, phosphate, scale inhibitor can prevent the deposition of alkaline earth metal scale on the drill string.

33

FIGURE 8: DUSTING BLOOIE LINE

Mist Drilling

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.


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.

.

FIGURE 9: MIST DRILLING OPERATION

34


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

35

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

 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.

 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.


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

 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.

36

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.

37

FIGURE 10:F OAM IS R ELATIVELY N EW FLUID TO T HE 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.

The foam quality

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


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 %).

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).

38

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

39

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

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

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.


 

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.

40


 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 30 0)  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

41

 No formation damage with no influx into the well bore.  Minimal pressure surges.  Controllable pressures.

Limitations for Foam Drilling    

   

 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


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

General Foam Types  Stable foam  Foaming agent

Stiff

 Polymer  Stiff foam

Foam

 Polymer  Bentonite  pH sensitive foam (amphoteric)  Transform

PH Sensitive

Stable

FIGURE 12: FOAM TYPES

42

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

43

 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.

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.

 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


Costs involved with aerated fluid drilling are primarily related to the composition of the drilling fluid being utilized and corrosion inhibition.

44 FIGURE 13: DIFFERENT TECHNIQUES OF UBD

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.

45

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

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.

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.


There are techniques, such as adding more gas before connections, which help reduce the ensuing pressure surge.

F IGURE 15: P ARASITE STRING INJECTION TECHNIQUE

46


3. Annular injection (Injection through Parasitic Liner) Annular injection through a concentric casing string is most commonly used in a number of offshore projects. This method is worthwhile if a suitable casing or completion tubing scheme is installed in the well. For a new drill well, a liner should be set just above the target formation. The liner is then tied back to surface using a modified tubing hanger to suspend the tie back string.

Gas is injected in the casing liner annulus to facilitate the drawdown required during the drilling operation. The tie back string is then pulled prior to installation of the final completion. The alternative is for an older well to have a completion in place incorporating gas lift mandrel pockets. These can be set up to provide the correct bottom hole pressures during the drilling operation. The drawback with this type of operation is that the hole size and tools required are restricted by the minimum ID of the completion. However, the main advantage of using an annulus to introduce gas into the system is that gas injection can be continued during connections, thus, creating a more stable bottom hole pressure. As the gas is injected, via the annulus, only a single-phase fluid is pumped down the drillstring. This has the advantage that conventional MWD tools operate in their preferred environment, which can have a positive affect on the operational cost of a project.

A parasitic liner or dual casing string serves the same basic purpose as the parasite string. If gas were continuously injected during drilling and connections without upsetting the entire circulating system, it should be possible to lighten the mud column and limit pressure surges.

FIGURE 16: ANNULAR INJECTION TECHNIQUE

47

4. Jet-sub (bypass joint) Application In areas of lost circulation, or to avoid major pressure surges on trips and connections, a bypass in the drill string below the fluid level in the hole would preferentially pass gas over fluid and start unloading the upper part of the hole.


An important problem when pumping everything down the drill pipe is that there is a huge volume of non-aerated fluid in the hole. Using air and fluid to unload the hole can cause a major pressure surge. In the case of lost circulation, it might take 1000 bbl of mud lost before returns could be regained. Jet subs ease this problem by unloading from up hole.

Figure 17: Jet-sub Applicatin

48

Flow drilling The term “flow drilling” refers to drilling operations in which the well is allowed to flow to surface while drilling.


All UBD operations are really flow drilling operations, but the term is usually applied to drilling with a single phase mud, and no gas is injected except by the formation. Flow drilling occurs when a permeable formation is intentionally drilled with a drilling fluid that encourages the formation to flow during drilling operations. Most commonly, the fluid influx will be from a hydrocarbon-bearing formation, and the flow returning to surface will consist of oil, natural gas and the drilling fluid. When flow drilling, well control problems are handled at the surface rather than down hole. Specific down hole and surface equipment are required for safe and efficient flow drilling operations.

Mud cap drilling Overview Sometimes, uncontrollable loss of circulation occurs during flow drilling operations. The driller is faced with higher annular pressures than can safely be handled with the rotating head or RBOP equipment. One technique, called “mud cap drilling,” can be used to overcome this situation. In mud cap drilling, the driller loads the annulus with a heavy, viscosities fluid, often saturated brine, and shuts-in the annulus of the well. The shut-in surface pressure on the annulus, plus the increased hydrostatic pressure resulting from this viscous pad, will equal the formation pressure. Viscosification of the pad should be designed to minimize gas migration up the annulus. The annular column is held in place by its density and the bull heading pressure of the rig pumps. It may be periodically necessary to add fluid to this mud cap, to offset annular losses to the formation during connections or trips. Drilling may then be resumed by pumping a clean fluid that is compatible with the formation fluids down the drill pipe, while the choke is closed and the well remains shut-in. This “blind” drilling approach with a sealed annulus results in bull heading all drilling fluid pumped with no return flow. Obviously, the formation must be able to freely accept these fluids and the fluid used must readily be available and relatively inexpensive. This process requires specialized well control and circulating equipment; however, unlike flow drilling, it does not require an extensive fluid separation system, since the formation fluids are kept down hole.

Applications of mud drilling

49

   

Highly fractured and vugged formation Sustained surface pressures in excess of 2,000 psi, Sour oil and gas product on, and, Small diameter wellbore's (3 7/8-inches up to 4%-inches).

Snub drilling is simply an underbalanced drilling operation that involves the use of a snubbing unit or a coiled tubing (CT) unit. The additional expense of this equipment can be justified if very high formation pressure and uncontrollable loss of circulation are expected. Often, personnel safety considerations provide the necessary reasons for snub drilling. Finally, if sour gas is expected, there is additional motivation. Both snubbing and CT units have BOP stacks that allow a drill string (coiled tubing in the latter case) to be run into or out of the hole, at much higher pressures (routinely up to 10,000 psi) than can be tolerated by either a rotating head or an RBOP. Both units also allow the drill string to be pushed into a well under pressure, even when the weight of the string alone is insufficient to overcome the pressure tending to push it out of the well. Snubbing and CT units can be used for underbalanced drilling, at pressures that cannot be managed by conventional drilling rigs.

Closed system An underbalanced drilling technique that involves using a specific type of surface system, rather than a specific drilling fluid. The distinguishing feature of this technique is the use of a pressurized, four-phase separator and a fully closed surface system, to handle the fluids returning from the well. These systems can safely manage natural gas production containing hydrogen sulfide, prevent hydrocarbon vaporization from open pits, (i.e. environmental benefits) and, with appropriate instrumentation, allow continuous measurement of a well's productivity. With planning, closed systems can be designed for high pressures, when drilling deep and over-pressured reservoirs.

Limitations


Snub drilling

Planning is required before using closed systems when high surface pressures are possible. Precautions are a1so required if the drilling fluid is oxygenated. Other limitations include availability of suitable equipment and personnel and increased operating costs. Using a closed system does not remove any of the specific limitations associated with the drilling fluid (other than air) or the technique adopted. 1234-

High Surface Pressures. Oxygen Containing Drilling Fluids Equipment and Personnel Availability Operating Costs

50

References 

Medley, G.H., Stone, R.C., Colbert, W.J., and McGowen III, H.E.: Underbalanced Operations Manual, Signa Engineering Corp., Houston (1998).



Underbalanced Drilling Manual, Gas Research Institute Publication, GRI Reference No. GRI-97/0236, 1997.




51

Gatlin, C., Petroleum Engineering: Drilling and Well Completions, Prentice-Hall, 1960.



Bourgoyne, A. T., et al, Applied Drilling Engineering, SPE, First Printing, 1986

52

Of underbalanced drilling technique Underbalanced drilling is technically feasible in almost all situations. There will be many instances when it is also the most cost effective procedure. This chapter summarized various techniques for drilling a well underbalanced, determining if underbalanced drilling is potentially applicable, selecting the potential underbalanced drilling methods, and, evaluating the economics to identify the most cost effective procedure.

53

RESERVOIR ASPECTS OF UNDERBALANCED DRILLING Before an underbalanced drilling operation is undertaken, a significant amount of work needs to be carried out by the reservoir engineers. Not only is an accurate reservoir pressure required but the damage mechanism of the reservoir must be understood to ensure that the required benefits are indeed possible. Certain wells or reservoirs are good candidates for underbalanced operations and result in an enhanced recovery. Other formations or fields may not be suited to underbalanced drilling for a variety of other reasons. A summary of indicators that help to determine whether a particular reservoir will be a good or bad candidate for UBD is listed below.

Good Candidate Indicators for UBD          

Depleted reservoirs. Typically exhibit lost circulation and differential sticking problems. If formation is consolidated, makes an excellent candidate. Naturally fractured and vugular formations. Usually exhibit huge losses, which can exacerbate well control problems or lead to differential or mechanical sticking, making them good candidates for UBD. Hard rock formations. Are usually consolidated and sustain UBD. Good candidates because of the improvement in ROP and bit life from UBD. Highly permeable formations. Once again exhibiting lost circulation and/or differential sticking, making them good candidates. Formation damage problems. Formation that usually suffer major formation damage during drilling or completion operations. Wells with a skin factor of 5 or higher is a good candidate. Any situation where ROP can be economically increased and fewer bits are required. Wells with massive heterogeneous or highly laminated formations that exhibit differing permeabilities, porosities or pore throats throughout. High production reservoirs with low-medium permeability. Formations with rock-fluid sensitivities. Formations with fluid-fluid sensitivities.

UBD is not a technology that should be utilized for all situations. Utilizing the technology in the wrong application may create an unsafe situation, increase formation damage, increase the probability of well failure or increase well cost with no probability of economic gain.

54

Bad Candidate Indicators for UBD  

    

   

Poor quality reservoirs. UBD cannot make a formation something that it is not. High pore pressure coupled with highly permeable formations. Are usually easily drilled overbalanced. UBD conditions are easily achieved, but the rates can be too high, leading to excessive drawdown, impractical surface equipment requirements, and associated problems. Shallow wells. Difficult to control bottomhole pressure and ensure continuous underbalanced conditions. Swelling shale and unstable formation. Wellbore stability problems if underbalanced. Formation susceptible to spontaneous imbibitions. UBD can exacerbate formation damage. Wells where drilling calls for frequent trips. Could create excessive oscillation between underbalanced and overbalanced conditions, causing damage, and eliminating the advantages of UBD. Candidates requiring UBD for long intervals. Although UBD can be achieved, the drawdown at the heel of the open hole intervals is likely to be very high when the bit is near the toe of a long interval, requiring impra impractical surface equipment requirements. Highly unconsolidated formations which require elevated wellbore pressure to maintain hole stability. Formations where knowledge of reservoir pressure is poor. Reservoir pressure drives the design of the UBD condition. Wells with high H2S. Producing fluids that contain high levels of H2S will complicate the system design and may pose a safety risk. Hole sections with variations of pressure. The drilling of a section that contains formations with a wide variation in formation pressures may lead to cross flow or require impractical surface equipment requirements. Sometimes it may be feasible to reduce the wellbore sufficiently so that all zones produce into the well.

55

OPTIMUM SELECTION OF UNDERBALANCED TECHNIQUES In this section we will discuss our new UBD design system which helps the engineer to achieve proper planning for UBD operation in order to achieve success for a particular well or project.

Compatibility of Fluids. Fluid compatibility is a major concern when designing an underbalanced system. Compatibility issues include compatibility with components of the injected fluid, injected fluid to produced fluid compatibility, and injected fluid to formation. 

Compatibility of Base Fluids: Selection in the base fluids (liquid and/or gas) is important. Incompatible base fluid can lead to the formation of emulsions and precipitates. Incompatibility of the fluids can also increase the corrosion rate. Fluid compatibility is critical in the design of the foam system. The make up fluids can affect the foam stability of the system.



Injected Fluid to Produced Fluid Compatibility: The mixing of produced fluids and injected fluids downhole can lead to the creation of emulsions, highly corrosive fluids, and poor foam stability. Analysis must be done to assure that the reservoir fluid and injected fluid do not create an emulsion that will affect the frictional pressure loss or the ability to separate the water, liquid hydrocarbons, solids, and gas at the surface. These issues are only pertinent in oil reservoirs. If foam is planned for a well, the stability of the foam must be analyzed. This analysis must be done with a mixture of the foam with the reservoir fluid. Many reservoir fluids can destroy foam stability. These include hydrocarbon, CO2, and salt. If a gas containing oxygen is used, the explosive limit of the injected fluid and the reservoir fluid must be determined. This is particularly important in the presence of H2S. If there is no H2S, standard limit tables will suffice.

Phase Trapping. The loss of both water-and oil-based drilling mud filtrate

56

to the formation in the near-wellbore region caused by leakoff during OBD operations, or by spontaneous imbibition in some situations during UBD, can result in permanent entrapment of a portion or all of the invading fluid. Phase trapping refers to the permanent increase in trapped fluid saturation (water, gas, or hydrocarbon) in a porous medium. The blockage of the entrained fluid

causes a reduction in the relative permeability to oil or gas that results in a zone of potentially significant damage surrounding the wellbore region. In Fig.1, increasing the water saturation from 20% to 35% decreases the relative oil permeability from 90% to 30%, respectively.

FIGURE 1: RELATIVE PERMEABILITY CURVE

Regular situations which may result in phase trapping may include the following:  Invasion of water-based fluids/filtrates into regions of low water saturation and resulting trapping effects on consequent drawdown.  Invasion of oil-based fluids/filtrates into zones of low or zero oil saturation and resulting trapping effects on subsequent drawdown.  Production of rich, retrograde-condensate-type gases below the dewpoint pressure resulting in the accumulation and trapping of critical retrograde-condensate saturation in the near-wellbore region.  Production of black oils below the bubble point resulting in the release of gas from solution and the formation of trapped critical-gas saturation.  Injection of free gas (aerated fluids and foams during poorly designed UBD operations, nondeoxygenated brines, nitrogen-energized fluids, etc.) into a fluid-saturated zone resulting in the creation of trapped critical-gas saturation. The main reason for UBD in such a situation is to prevent the significant loss of potentially damaging and trapping of water- or oil-based filtrates into the formation, thereby reducing and mitigating the potential severity of damage associated with phase trapping effects.

57

Bacterial Damage. Bacterial damage is associated with the introduction of viable bacteria to the formation. Bacteria may colonize and propagate in either an aerobic (requiring oxygen to survive) or anaerobic (not requiring oxygen to survive) fashion. Although most commonly associated with water injection operations, bacterial damage has the potential to occur any time a water-based fluid is introduced into a formation. Bacteria can grow in many different environments and conditions: temperatures ranging from 12°F to greater than 250°F, pH values ranging from 1 to 11, salinities to 30% and pressures to 25,000 psi. The three major damage mechanisms associated with bacterial damage include the following:  Plugging: Most bacteria secrete a viscous polysaccharide polymer as a byproduct of their life cycle; these polymers may adsorb and gradually plug the formation.  Corrosion: Some types of bacteria set up an electrokinetic hydrogenreduction reaction which can result in pitting and hydrogen-stress cracking on metallic surfaces downhole in tubing or in surface equipment.  Toxicity: A certain type of anaerobic bacteria, commonly referred to as sulfate reducing bacteria (SRB) reduce elemental sulfate, which may be present in formation/injection waters and create toxic hydrogen sulfide gas. The correct use of UBD technology prevents the continuing losses of potential water-based fluids which may contain viable bacteria colonies into the formation. On the other hand, in most situations, if water-based fluids are contemplated for any UBD operation, an appropriate bacterial and biological control is recommended. Bacteria problems are often treated with oxidants, such as sodium hypochlorite, and often various types of biocides are also used. The ability to have other formation damage mechanisms such as fluid/fluid incompatibility, rock/fluid incompatibility, phase trapping, and chemical absorption in any drilling operation has been studied by Bennion.

1.1 ASSESSING LOST CIRCULATION POTENTIAL

58

Lost circulation is defined as the partial or total loss of drilling fluids to the formation being penetrated. It occurs when natural, or induced formation openings are large enough to allow mud to pass through, and when the pressure applied by the mud column exceeds formation pore pressure. The severity of these losses varies from minor seepage losses to a complete loss of the returns. These losses can occur in unconsolidated or highly permeable formations, in

naturally fractured formations, in formations with induced fractures, or in cavernous formations.

1.2 ASSESSING PIPE STICKING POSSIBILITY In many reservoirs, differential sticking is a major problem causing significant nonproductive time (NPT). Economic losses are compounded by the potential loss of the BHA and the possibility of having to sidetrack the hole around the lost pipe. Differential sticking occurs because of the filter cake (which has other beneficial effects, as we shall see, but in this case can be harmful) and the differential pressure between the fluid in the annulus and the formation. Since a filter cake cannot be completely impermeable, a pressure gradient exists across the filter cake in the overbalanced condition. If the drill pipe embeds into the filter cake, this pressure gradient acts as a force holding the drillpipe against the wellbore wall. The holding force is determined by multiplying the differential pressure by the cross sectional area of the pipe imbedded in the wall cake. If the holding force exceeds the ability of the rig to move the pipe, it will become differentially stuck.

UBD eliminates both the filter cake and the differential pressure. As most multiphase fluids do not have solids that produce the filter cake, one will not be generated. In underbalanced operations differential pressure acts from the reservoir to the annulus. If designed properly, it is impossible to have positive differential pressure in underbalanced operations.

1. GENERAL CONSIDERATION TO SELECT DRILLING FLUID In designing an underbalanced fluid system, information on the reservoir characteristic, hole geometry, availability, environment and offset history must be considered. The following data must be evaluated when selecting an optimum fluid for an underbalanced drilling (UBD): 1. Reservoir characteristics:  Formation type (such as sand, limestone, and clay).  Pore pressure.  Temperature.  Formation bearing fluid (such as water, oil and gas) and characteristics (such as composition, water gas, and PVT).  Geophysical/geomechanics information.  Permeability and porosity.

59



Compatibility between reservoir fluids.

2. Well geometry:  Directional characteristics.  Hole size.  Proposed casing program. 3. Environmental:  Disposal (Cuttings, production fluids, and drilling fluids). 4. Offset history:  Mud logs, production history, well test data, seismic, and drilling reports.

FIGURE 2: DRILLING FLUID ACCORDING TO FORMATION TYPES

60

2.1 Well fluid design consideration Like the fluid design for conventionally drilled wells, the fluid system in an underbalanced wells is the transportation system for bringing the cuttings to surface, cools and lubricates the bottom hole assembly and helps control the bottom hole pressure. Fluid system design is one of the most overlooked parts of underbalanced projects. In designing an underbalanced fluid system the impact on the desired equivalent circulating density must be considered. The equivalent circulation density is a combination of annular fluid density, frictional pressure loss in the annulus, and surface choke pressure. The design must result in a pressure that is below the formation pressure, but not so low that it creates hole stability problems or excess production. Compatibility between the components of the fluid system, the fluid system with produced fluids and the fluid system with the formation is all critical in the fluid selection. Incompatibility can lead to formation damage or the creation of emulsions. Formation fluids may also affect the characteristics of the fluid system. Acid gases or hydrocarbons will affect the stability of most foam. Hole cleaning is always a concern in underbalanced wells. Most underbalanced fluid systems rely on the velocity of the fluids, not the viscosity to clean the hole. Different fluid systems will require different velocities to achieve adequate hole cleaning. The carrying capacities of underbalanced fluids range from extremely poor for pure gas systems, to extremely good in foam systems. Temperature stability must also be considered in designing an underbalanced fluid system. Many of the chemicals used may break down with high temperatures. These include surfactants and viscofying agents. Temperature will also affect the density of the fluids used in designing the system. As fluids are heated, their density falls. This is especially true for brines and oils and is critical in designing kill weight fluids. Corrosion is a concern in designing underbalanced fluid systems. As the well is being produced, the interaction of the produced fluid, injected gases, and injected liquid may create an environment that promotes high corrosion rates. Corrosion problems are accelerated, because the circulated solids remove any corrosion barriers that are naturally formed. The effect on downhole tool must also be considered in the selection of the underbalanced fluid system. This includes the compressibility of multiphase fluids, which lower the power output of the motors. Compatibility of the fluid with elastomers must also be considered. This can affect the functionality and longevity of the mud motors and downhole measuring devices. This infusion of the gas into elastomers can also lead to explosive decompression of the elastomers during trips. Downhole tools (such as tools with no elastomers)

61

should be selected that will not be effected by the fluid or a fluid system should be designed that mitigate the effect on downhole tools. Fluid selection will also affect the ability to transmit data from downhole. Gas is a compressible fluid; if gas is used in the fluid system, it may dampen or eliminate any signal transmitted downhole. Health, safety and environmental must be considered in selecting an underbalanced fluid system. The system must be designed so that fluids can be handled safely at surface. Both produced fluids, solids, and injected fluids must be handled in a minor that meets local regulations. It must be remembered that the returned fluid will be contaminated with produced fluid. This will affect the disposal of the solids and all returned fluids.

2.1.1

Equivalent Circulating Density

Achieving the desired bottom hole pressure is a combination of the fluid density, applied surface pressure, and annular friction. The selection of the fluid system will affect both of these components. The density of the base fluid, both liquid and gas, will impact the density of the fluid system. The properties of the fluid system will also affect the friction that will be generated. This will be compounded by the interaction of the fluid system with produced fluid. Mixing of the produced and injected fluids will change the viscosity of the fluids, which may have a severe impact on the friction loss.

2.1.2

Hole Cleaning Issues

Hole cleaning is always a major concern in an underbalanced operations. Hole cleaning requirements will be determined by the geometry of the well (including washout) and the rate of penetration. The fluid must be selected that will meet the hole cleaning requirements. The fluid used will have a significant impact on the carrying capacity of the system. When indications of poor hole cleaning are seen, using viscous pills as sweeps can be used to eliminate cutting beds. The viscous pill may be foam (for nonfoam based systems) or a polymer pill. The pill should be large enough to cover 500 feet of the open hole annulus. Due to the problems of separating the gas and solids from a highly viscous pill, attempts should be made to capture and dump the pill when it returns to surface.

2.1.3

62

Pore Pressure

The pore pressure in formations that will be open to the borehole is the upper limit for the range of borehole pressures which will give underbalanced conditions. The drilling technique adopted must result in a borehole pressure which is less than the pore pressure in all open zones.

This restriction can only be relaxed for open zones that will not be influenced by overbalance. In practice, the borehole pressure at any depth will fluctuate during drilling, principally when circulation is shut down to make a connection or to trip the string.

If there is no formation fluid inflow, borehole pressures with dry gas, mist, foam or pure liquid drilling fluids will normally decrease when circulation is stopped. Therefore, if it is established that underbalanced conditions will result during circulation, they will likely be maintained if circulation is stopped, unless there is an overwhelming fluid influx

The borehole pressure can change significantly when gasified liquid is used. It may either increase or decrease, depending on the connection and tripping procedures. As a generalization, the borehc le pressure will probably increase during a connection when drilling with a liquid gasified by drillstring gas injection. In practice, if it is generally not possible to maintain a circulating pressure that is 300 to 500 psi less than the pore pressure, underbalanced conditions may not be maintained during connections, when drilling with a gasified liquid.

2.1.4

Wellbore Stability

Just as formation pore pressure is an upper limit to allowable underbalanced pressures, a lower limit may be established by the minimum pressure required to maintain hole stability. In underbalanced drilling: When there is an aqueous component in the drilling fluid, water-wet formations may still imbibe water when drilled underbalanced. Precautions for inhibiting the base fluid should still be taken (when drilling underbalanced) and exposure to diluted formation fluid from greater depths should also still be considered. The effects of desiccation (drying out), when a formation is contacted with circulating dry gas, are not well defined in the literature. Imbibition into the formation would seem to be inhibited. If the water content reduces, the strength may increase However, desiccation cracking may occur during shrinkage and some sloughing may occur. This may heighten imbibition if water does ultimately contact the shale. In sands, the strength may also be increased because of increasing capillary forces. Less dampening of vibrations may cause greater formation disaggregation uphole from the bit.

63

2.1.5

Temperature Effect

Temperature is critical in determining the risk of exceeding the flash point of liquids. It will also impact the bottom hole pressure. Temperature will also impact surface and downhole equipment. Temperature also has an impact on the corrosion rate that will occur and the stability of the fluid. Temperature will also impact the chemical and foam stability. Determining the temperature profile for underbalanced wells is not straightforward. The velocity of the fluids, the amount of inflow, the expansion of gas, the temperature of the surrounding formation, geometry, inlet temperature, and the specific heat of the fluids and surrounding material impact the temperature profile. Determining the temperature profile and the impact on the design requires an enhanced computer simulator.

2.1.6

Water Production

The flow of formation water into the borehole can influence the selection of suitable drilling technique Production of even small volumes of water can make dry gas drilling difficult. A mud ring can form as damp cuttings collect, usually at the top of the BHA where the annular velocity is lowest. It is common to switch to mist, or even foam, if a water inflow is encountered. When onset wells indicate that formation water inflows are probable, the operator should not expect to drill below the water producing zone with dry gas. When misting, higher air injection rates are required to lift the water from the hole. The air rate must be sufficiently high to prevent slug flow. Slug flow can damage the borehole and surface equipment. The high air rate, in combination with tie weight of water in the annulus, significantly increases the standpipe pressure. Boosters are often needed to increase the gas delivery pressure when substantial water inflows are encountered. More compressor power is required. If nitrogen or natural gas are used as the gas phase, the gas Supply cost will be greatly increased. Hole size also influences the impact of water inflow on required gas injection rate and pressure. Increased cross-sectional area reduces annular velocity and hole cleaning efficiency, although large holes can usually produce more water before the gas injection pressure becomes impractically high. When large water inflows are anticipated, dry gas or mist drilling may not be appropriate, even if wellbore stability and hydrocarbon production rates indicate that these drilling fluids would be nominally acceptable.

64

TABLE 1:U NDERBALANCED DRILLING APPLICATIONS AND C ANDIDATE T ECHNIQUES

Reason for Drilling Underbalanced

Preferred Underbalanced Drilling Technique

Low ROP through hard rock.

(1)

Dry air.

(2)

Mist, if there is a slight water inflow.

(3) Foam, if there is heavy water inflow, if the borehole wall is prone to erosion, or if there is a large hole diameter. (4) Nitrogen or natural gas, if the well is producing wet gas and it is a high angle or horizontal hole. Lost circulation through the overburden.

(1) Aerated mud, if the ROP is high (rock strength low or moderate) or if water-sensitive shales are present. (2) Foam is possible if wellbore instability is not a problem.

Differential sticking through the overburden.

(1) Nitrified mud, if gas production is likely, especially if a closed system is to be used. (2) Aerated mud, if gas production is unlikely and an open surface system is to be used. (3) Foam is possible if the pore pressure is very low and if the formations are very hard.

Formation damage through a soft/medium- (1) depleted reservoir. •

Nitrified brine or crude: String injection, if the pore pressure is very low;

• Parasite injection, if the pore press ire is high enough and a deviated/horizontal hole needs conventional MWD and/or a mud motor. 

Temporary casing injection, if the pore pressure is intermediate and a high gas rate is needed. • String and temporary casing inject Ion, if the pore pressure is very low and/or if very high gas rates are required with a closed surface system. (2) Foam, if the pore pressure is very low and an open surface system is acceptable. Formation damage through a normally pressured reservoir.

Flowdrill (use a closed surface system If sour gas is possible).

Lost circulation/formation damage through Flowdrill (use an atmospheric system If no sour gas is a normally pressured, fractured reservoir. possible). Formation damage through an overpressured reservoir.

Snub drill (use a closed surface system if sour gas is possible).

65

FIGURE 3: FLOW CHART FOR UNDERBALANCED DRILLING CANDIDATE SELECTION .

66

FIGURE 4:FLOW CHART OF DRILLING FLUID SELECTION FOR VERTICAL WELL .

67

FIGURE 5:FLOW CHART OF DRILLING FLUID SELECTION FOR HORIZONTAL WELL .

68

UNDERBALANCED DRILLING OBJECTIVES IN OBAYED D-2 Primary objectives:  Treatment of losses  Potential of formation damage Secondary objective:  Rate of penetration enhancement Other Objectives 

Low permeability (0.1-1.0mD) gas sandstone. UB techniques required to reduce formation damage. Loss circulation issues have curtailed horizontal reach in recent well.

Reasons for evaluating underbalanced drilling (ROP, Productivity Improvement, etc) Productivity enhancement due to impairment during conventional drilling practices. Secondary benefit to allow extended reach in wells exhibiting fractures/high loss circulation

Fluid Selection Fluid selection for underbalanced drilling operations can be extremely complex. Key issues such as reservoir characteristics, geophysical characteristics, well fluid characteristics, well geometry, compatibility, hole cleaning, temperature stability, corrosion, drilling BHA, data transmission, surface fluid handling and separation, formation lithology, health and safety, environmental impact, fluid source availability, as well as the primary objective for drilling underbalanced all have to be taken into consideration before the final fluid selection can be made.

The objective of the fluid selection system is to select the optimum drilling fluid for underbalanced drilling operations that meets all the health, safety, and environmental requirements as well as the required technical requirements.

The planned wellbore geometry: horizontal

To calculate this initial fluid density required, simply convert the reservoir pressure and the drawdown into an equivalent fluid density. Fluid gradients are calculated based on the following formula:

69

Fluid gradient (ppg) 

Preservoir  Psurface  Pdrawdown 0.052  TVD

Where: Surface Pressure is assumed to be approximately 150 psi And the reservoir Drawdown is assumed to be 250 psi

At Preservoir=5900 psi & TVD=3968.87 m=13018 ft Fluid gradient=8.2 ppg

Underbalanced fluid systems have been categorized by the IADC by the following system (Table 1): FIGURE 6: IADC FLUID CLASSIFICATION

70

Fluid System.

Specific Gravity.

Equivalent Mud Weight (ppg).

Gas Drilling

0-0.02

0-0.02

Mist Drilling

0.02-0.07

0.2-0.6

Foam Drilling

0.07-0.6

0.6-5

Gasified Liquid drilling

0.55-1.0

4.5-8.5

Liquid drilling

0.82 and above

6.9 and above

Reservoir Data: TABLE 2: OBAYED RESERVOIR DATA

Formation

Lower Safa Eastern Area

Lower Safa Western Area

Top (m – TVD)

3800

3800

Bottom (m – TVD)

3900

3900

Pore Pressure

5400 psi

5900 psi

Frac Pressure / Gradient

0.55-0.6psi/ft

0.75 psi/ft

300

300

Permeability

1.0 – 10

0.1 – 1.0

Potential Fractures

Possible

Possible

Fracture Orientation

Not Known

Not Known

Sonic Velocity

0.005m/ms

0.005m/ms

BHT deg F

Youngs Modulus Poissons Ratio Cohesion Friction Angle Density Borehole Stability Issues

35Gpa 0.25 13Mpa / 1885psi 55 deg 2.65 s.g. None in the reservoir section

71

Compositional Data: Mole Fraction Composition Data

0.8000 0.7000 0.6000 0.5000 0.4000 0.3000 0.2000 0.1000 0.0000 C1

C2

C3

C4

C5

C6

C7+

H2S

N2

CO2

FIGURE 7: OBAYED COMPOSITIONAL DATA

The IADC Underbalanced Operations Committee has been working to promote the safe and efficient application of underbalanced operations (UBO) worldwide. One of the main achievements of the committee is the recent adoption of the following standard classification system for UBO and a set of standard nomenclature, which are listed in the table TABLE 3:IADC UBO C OMMITTEE C LASSIFICATION SYSTEM FOR U NDERBALANCED WELLS

Level

72

Description

0

Performance enhancement only; no hydrocarbon containing zones.

1

Well incapable of natural flow to surface, inherently stable, and a low-level risk from a well control point of view.

2

Well capable of natural flow to surface but enabling conventional well control methods and has limited consequences in the case of catastrophic equipment failure.

3

Geothermal and non-hydrocarbon production. Maximum shut-in pressures are less than UBD equipment operating pressure rating. Catastrophic failure has immediate serious consequences.

4

Hydrocarbon production. Maximum shut-in pressures are less than UBD equipment operating pressure rating. Catastrophic failure has immediate serious consequences.

5

Maximum projected surface pressures exceed UBO operating pressure rating but are below BOP stack rating. Catastrophic failure has immediate serious consequences.

The matrix in Table 4 classifies the majority of known underbalanced applications. This system combines the risk management categories previously defined (Levels 0 to 5) with a sub-classifier to indicate if wells are drilled “underbalanced" or with a "low head" using underbalanced technology. In order 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. TABLE 4:IADC UBO C OMMITTEE C LASSIFICATION M ATRIX UBO Application Type

Term

Description

A

Low-head or Condition where the hydrostatic head of the well bore near balanced fluid column is reduced to be either in balance or slightly greater than the formation pressure, thus not drilling. planning to induce hydrocarbons or formation fluids into the well bore.

B

Underbalanced Planned condition where the bottom-hole pressure drilling (UBD). exerted by the hydrostatic head of the fluid column is less than the formation pressure being drilled.

1

Gas drilling.

Drilling process using only gas as the chilling medium: no intentional fluid added.

2

Mist chilling.

Drilling with liquid entrained in a continuous gaseous phase: typical mist systems have <2.5% liquid content.

3

Foam drilling.

Drilling with a two-phase fluid and a continuous liquid phase generated from the addition of liquid, surfactant, and gas: typical foams range from 55% to 97.5% gas.

4

Gasified liquid drilling.

Drilling with a gas entrained in a liquid phase.

In obayed D2, A horizontal section is drilled using a drilling fluid lightened with nitrogen gas to achieve an underbalanced condition through the reservoir section. The maximum predicted bottomhole pressure is 5,900 psi with a potential surface shut-in pressure of 1200 psi.

(It as would be classified as a 4-B-4 indicating Classification Level 4 risk, and UBD drilling with a gasified liquid).

73

2. ECONOMIC STUDY MODEL The only reason to employ UBD technology, or any technology, is to generate profits. Misapplying technology will not only hurt the project economics, but it also damages the perception of the technology. As UBD will result in a higher frontend engineering cost and higher effective day rate, the gain from employing the technology must offset the additional cost. Profit can be gained by: • • • • • • •

Reducing direct drilling cost by increasing ROP and bit life. Eliminating expensive fluid systems. Decreasing stimulation cost. Decreasing trouble time. Increasing the deliverability of the well (accelerated production). Value of produced fluid while drilling. Increasing the ultimate recovery from the reservoir.

Unfortunately, many of the factors that affect the economics of an underbalanced project are not well known. Experience has shown that the ROP and bit life will increase when UBD is employed. Experience has also shown that UBD is effective in reducing or eliminating lost circulation or differential sticking problems. It is also well understood that drilling underbalanced will reduce or eliminate formation damage. What is difficult to quantify is the magnitude of the change that can be expected. The cost of an underbalanced system is easier to quantify. Cost analysis must not only include the cost of equipment and personnel, but it must also include the cost of pre-engineering, training and project management. For a first time application of UBD for a company or in a region, UBD adds a degree of complexity over conventional drilling that must be managed. An improperly designed or managed project can greatly increase the cost, risk of failure and risk of accidents. The complexity and cost are further exaggerated with first-time applications in an offshore or remote application.

Cost of UBD

74

While drilling hydrocarbon-bearing formations in the UBD mode, the reservoir fluid flow from the reservoir into the borehole and the productive capacity of the formation are immediately known. This cannot be accomplished without adequate preplanning and specialized equipment. Additional equipment used in safe UBD includes: rotating control head, diverter/rotating BOP, multiphase separators, compressors/boosters, nitrogen membrane unit, and specialized personnel. The incremental cost can be more than conventional drilling operations. However, there are trade-off costs with UBD (i.e. low mud costs, no DST, faster ROP, less

cement volume). The benefit of planning for UBD and the detection of hydrocarbon flow in a controlled manner occurs real-time. Item

Areated Drilling

Mud Drilling

Interval

From 13727 ft to 14360 ft

From 13727 ft to 14360 ft

Interval Length (F) (ft)

633

633

Penetration Rate (ft/hr)

10.23

5.115

Rotating Time (t) (hr)

62

124

Bit Life (hr)

31

31

Bits Required

2

4

Unit Bit Cost

$ 4,800/bit

$ 4,800/bit

Bit Cost (B)

9600

19200

Trip Schedule

Trip in to 13727 ft

Trip in to 13727 ft

Trip out from 14044 ft


Trip in to 14044 ft

Trip in to 13885 ft


Trip out from 14044 ft Trip in to 14044 Trip out from 14202 ft Trip in to 14202 ft Trip out from 14360 ft

Total Trip Footage

56175 ft

112349 ft

Unit Trip Time

0.75

0.75

Trip Time (T) (hr)

16

32

Hourly Operating Cost

$ 570/hr

$ 570/hr

Cost / ft

[9600+Cr(16+62)] / [633]

[19200+570(124+32)] / [633]

[B+Cr(T+t)]/[F]

= $ 85.4/ft

=$ 170.8 /ft

(hr/500 ft)

(Cr)

75

TABLE 5:QUOTE FOR UBD PERSONNEL .

Personnel Costs

Day Rate

Travel

Project Management

2,500

3,500

UBD Consultant

2,500

3,500

HSE Consultant

2,000

3,500

UBD Supervisor 1

1,400

3,500

UBD Supervisor 2

1,400

3,500

UBD Engineer 1

1,500

3,500

UBD Engineer 2

1,500

3,500

UBD Lead Operator 1

1,300

3,500

UBD Lead Operator 2

1,300

3,500

UBD Operator 1

800

3,500

UBD Operator 2

800

3,500

UBD Operator 3

800

3,500

UBD Operator 4

800

3,500

1,100

3,500

UBD DAS Operator

700

3,500

RCD Lead Operator

500

3,500

Nitrogen superviosr

1,100

3,500

Nitrogen Operator 1

800

3,500

Nitrogen Operator 2

800

3,500

Nitrogen Operator 3

800

3,500

Nitrogen Operator 4

800

3,500

25,200

73,500

UBD DAS Operator

76

Lead

TABLE 6:SUPPLIER QUOTES . Equipment

Mob

Day Rate

Stand Rate

Surface Equipment

$ 50,000

$ 7,600

$ 3,800

N2 Equipment

$ 50,000

$ 6,200

$ 3,100

Rig rate

$ 32,000

$ 5,800

$ 2,900

MWD Tools

$ 10,000

$ 2,500

$ 1,250

RCH

$ 15,000

$ 1,800

$ 900

by

Cost comparison: Nitrogen versus Natural Gas The nitrogen drilling system [membrane generated] eliminates the downhole fire risks associated with air drilling in hydrocarbon producing formations while significantly reducing costs as compared to pipeline gas (methane) drilling or truckle liquid nitrogen drilling. Typically, wells that must be gas drilled through productive intervals rely on pipeline gas, expensive trucked liquid nitrogen, or airwater injection (mist) systems. General Assumptions  Flowrate ................................................ 3000 cfm  Gas Price .............................................. $2.00/mcf  Trucking Distance ................ 50 miles (one way)  Drilling Hours/day .......................................... .20  Average Gas Drilling Days/well ...................... 12  Diesel Usage/hour/unit ..................... 1.0.7 gallons  Diesel Fuel Price ............................. $0.80/gallon  Standby Days (Equipment)/well ........................ 4 TABLE 7: NITORGEN VS PIPELINE GAS Nitrogen Drilling System Cost

Pipeline Gas Drilling Cost

Compressors (8) @ $135/unit/day=135*8*12

$ 12,960

Pipeline gas 43.2 mmcf @ $2.00/mcf=43.2*2*1000

$ 86,400

Boosters (2) @ $200/unit/day (air use) =200*2*12

$ 4,800

Booster (2) $300/unit/day (gas use)=2*300*12

$ 7,200

Membrane Skids (2) @ $1,500/unit/day

$ 36,000

Drill Gas Unit (installed on location)

$ 1,000

Trucking/Transportation

$ 9,200

Gas Line (2,000 feet)

$ 1,800

Fuel (delivered)=12*20*(8+2)*10.7 gallons * $0.80/gallon

$ 20,540

Trucking/Transportation

$ 1,800

Mist Pump

$ 1,500

Fuel (delivered)=2*10.7*20*12 gallons * $0.80/gallon

$ 4,110

Equipment Standby (4 days)

$ 1,800

Mist Pump

$ 1,500

Equipment Standby (4 days)

$ 700

Total pipeline Gas Drilling Cost/well

$ 104,510

(1,800 cfm/skid) =1500*2*12

Total Nitrogen Drilling Cost/well

$ 88,600

77

Cost comparison: Liquid Nitrogen versus Membrane Nitrogen

78

•

Although operationally simple, the cost of the supply of the liquid nitrogen to the well site can represent a significant expense to the total UBD program.

•

Under optimum circumstances, the use of natural gas can be the most cost effective method for UBD programs with the only cost being the compression equipment. This can be minimal if a high pressure feed supply is available at the wellsite.

•

The suitability of nitrogen membrane systems to high pressure, short duration applications is not good. Only when the equipment is used over prolonged periods, at high utilization can it be made cost effective on land. Offshore applications are more affected by support logistics and obviously lend themselves to membrane technologies.

•

The system’s largest operating expense is the cost of fuel for the air compression units ... The advantage of the nitrogen membranes versus liquid nitrogen system is the ample supply of free nitrogen available in the air versus the cost of liquid nitrogen and the required transportation to site.

•

The process of gas recycling can be cost effective with the previous systems in very specific applications but is both technically and operationally challenging for most UBD programs.

T ABLE 8: LIQUID NITROGEN VS MEMEBRANE NITROGEN Item

Liquid N2

Portable N2 Generating System

Drilling Program

90 days

90 days

N2

1,500 scfm

1,500 scfm

Duration of N2 requirement

240 hrs (10 days)

240 hrs (10 days)

N2 Purity

Minimum 95 % (by volume)

Minimum 95 % (by volume)

N2 Pressure

5,000 psi

5,000 psi

1,500 scfm * 60 min/hr * N2 requirement

24 hr/day *10 days = 584,000 sm3

1,500 scfm * 60 min/hr * 24 hr/day *10 days = 584,000 sm3

= 834,000 liters liquid N2 = 139 tanks Method of N2 Supply

Logistics

Trucked in liquid N2

On-site membrane

(equipment rental)

(equipment purchase)

139 liquid N2 tanks, 1 evaporator and 1 diesel skid (141 containers)

4 skid maximum, 14 tonnes each, 1 power unit, 14 tonnes (5 containers) Electrical power: 1,400 kW * 10 days * 24 hrs @ $0.05/kWh

Cost of Utilities

$ 1,284,000

(liquid N2 , electricity, diesel)

Maintenance

= $ 16,800 (Power unit rental included in capital cost)

None

10 % of interest and depreciation $ 32,000

Capital Cost

None

Interest and depreciation over 10 years $324,000

Approximately TOTAL

$ 1,300,000

Approximately $ 375,000

79

Economic Analysis • • •

On the basis of available technology, select the potential drilling systems to be evaluated. Tabulate the tangible and intangible costs for each system. Rely on previous history and recognize the inevitability of statistical variation.

Perform basic cost/ft drilling evaluations. CT 

B  Cr (t  T ) F

Where:

80



CT……total cost/foot.



B…….bit cost.



Cr……hourly rig cost.



t……..rotating time.



T…….round trip time.



F…….footage per bit run.

Obayed Planning and Budget AFE T ABLE 9: OBAYED AFE

Completion

RATES

Preparation

Description

Rig Move

A/C no.

COST ESTIMATES Move

Preparation

Drilling

Completion

Total

7 days

11 days

18 days

9 days

44 days

( 1 day train)

4670 m

143,000

229,667

110,500

483,167

1,650

2,650

1,275

6,550

762,091

1,223,964

TIME DEPENDENT ($/day) 6121

Rig Rate

6461

Catering

6122

Drilling equipment rental

6134

Liner/Tubing running services

50

50

50

550

883

425

1,858

6145

Cement serv. & pers.

1,200

1,200

1,200

1,200

7,800

13,200

21,200

10,200

52,400

6151

Mud logging ON/line

360

360

360

360

2,340

3,960

6,360

3,060

15,720

6185

Wireline Services

17,000

39,000

7751

Fuel

1,500

1,500

1,500

1,500

9,750

16,500

26,500

12,750

65,500

TOTAL

3,210

87,541

85,541

18,260

20,865

962,951

1,511,224

155,210

2,650,250

25,750

25,750

283,250

454,917

150

13,000

13,000

13,000

150

150

150

69,281

69,281

2,000

975

2,000

22,000

1,986,055

DEPTH DEPENDENT ($/m) 6131

Deviation survey (one gyros) Directional work (MWD, PWD )

738,167

6141

Mud turnkey services

100,000

100,000

6142

Nitrogen operation

20,000

20,000

6145

Cement chemicals

7111

Bits + Core heads

180,000

180,000

7121

Casing and accessories

102,476

102,476

7141

Tubing, xovers and pup joints

47,500

47,500

904,893

1,188,143

TOTAL

283,250

FIXED COSTS ($) 6111

6123

Site preparation

40,000

40,000

Road Preparation

10,000

10,000

In field rig move + W.F Mobilization Equipment

94,000

94,000

347,500 441,500

Environmental Precautions ( EIA ) 7122

347,500

3,000 3,000

drilling equipment purchase ( Kelly hose ,X/O )

78,290

surface equipment ( export flow line material )

34,000

7142

Tubing accessories

112,000

Insurance (one off for Blowouts)

22,000

8671

7123

TOTAL

78,290

34,000 112,000

22,000 94,000

147,000

347,500

246,290

740,790

81

SUPPORT COSTS ($/day) OD overhead inc.consultants

2,650

2,650

2,650

2,650

17,225

29,150

46,817

22,525

115,717

500

500

500

500

3,250

5,500

8,833

4,250

21,833

6149

Other drilling expenses

6609

Bus service

100

100

100

100

650

1,100

1,767

850

4,367

9401

Air transport

1,000

1,000

1,000

1,000

6,500

11,000

17,667

8,500

43,667

9402

Land transport

270

270

270

270

1,755

2,970

4,770

2,295

11,790

29,380

49,720

79,853

38,420

197,373

197,245

1,643,421

2,742,260

193,630

4,776,556

TOTAL

4,520

4,520

GENERAL TOTAL TOTAL ESTIMATE

$

Time Estimate versus Actual OBA D2 UBD Time Tracking Planned vs Actual 32 30

Plan Actual

28.7

28 26 24 21.3

22 20 18 16 14 12 10 8 6

5.8 4.5

4 2 0 Rig Move

Prepare for UBD

Drill 3 7/8" Hole Leg A

OH Sidetrack

Drill 3 7/8" Hole Leg B

Run Completion (UBD)

FIGURE 8: TIME ESTIMATION

82

Retrieve 7" Tie back

Run 5" Completion

Suspend well

4,780,000

Time versus Depth Curve Time Depth Curve UBD D2 UBD from Spud to Release

Spudded 10th July 18:00 hrs Released 26th August 06:00 hrs

4160 UBD Preparation

4210 4260 4310

Drill 3 7/8" Leg A Depth [m]

4360 Drill 3 7/8" Leg B

4410 4460 4510

Completion

Prepare for UBD Drill Leg A: OH Sidetrack Drill Leg B Completion Suspend Well

30

40

4560 4610 OH Sidetrack 4660

0

5

10

15

20

25

35

45

Plan 11.0d 8.3d 1.0d 8.3d 8.5d 0.0d

50

Actual 28.7d 21.3d 0.0d 0.0d 0.0d 4.5d

55

60

Days Plan

Actual

FIGURE 9: TIME VS DEPTH

Cost Tracking Estimate versus Actual OBA D2 UBD Cost Tracking Planned vs Actual 3,000,000

Plan Actual

2,500,000

2,000,000

1,500,000

1,000,000

500,000

83 0 Rig Move

Prepare for UBD

Drill 3 7/8" Hole Leg A

OH Sidetrack

Drill 3 7/8" Hole Leg B

Run Completion (UBD)

FIGURE 10: COST TRACKING

Retrieve 7" Tie back

Run 5" Completion

Suspension

Cost Depth Curve Cost - Depth Curve OBA D2 UBD

Cost in $ $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

4160 4210 4260 4310

Depth in m

4360 4410 4460 4510 4560 4610 4660

Plan

Actual

FIGURE 11: COST VS DEPTH CURVE

84

Quantifying Productivity One of the main advantages of UBD is reduction in formation damage. Therefore the evaluation of the productivity is indispensable for the cost estimation. To evaluate the potential gains in productivity of a well, we must be able to estimate the potential decrease in the mechanical skin. In order to evaluate the productivity index and production volume for each vertical and horizontal case, the following equations are used in our system:

The productivity index (PI) for a vertical hole is:

0.00708Kh

PI 

  re     0.75  s    rw  

Bo ln 

The productivity index (PI) for a horizontal hole is:

PI 

0.00708KL 2     L        1  1   2r   L   h    e    s  Bo  ln   ln  L  h   2rw       2re      

Where 

k .......reservoir permeability (md),



h ...... reservoir thickness (feet),



p. ...... oil viscosity (cP),



Bo ....... formation volume factor (bbl/STB),



re ........ external radius (of reservoir) (feet),



L ........ length of horizontal reservoir (feet)



s ......... skin (dimensionless).



rw ........ wellbore radius (feet),

85

For a vertical well, if the reservoir is considered to be radial, prior to pseudosteady state conditions: 1

kh( Pi  Pwf )   kt q  log  3.23  0.87 s  (oil) 2 162.6 Bo    Ct rw  1

2

kh( Pi  Pwf2 )   kt q  log  3.23  0.87 s  (gas) 2 1637 ZT   Ct rw  where: 

q ......... rate (BOPD, MscfD),



Pi ....... average reservoir pressure (psi),



Pwf ...... wellbore pressure (psi),(dimensionless),



Z ........ real gas deviation factor



T ........ temperature, (OR),



t .......... time (hr),



Ct ........ total compressibility (psi-1).

At pseudo-steady state, for a radially flowing, vertical well:

q

q

q

86

0.00708KhPi  Pwf   r   Bo ln  e   0.75  s    rw  

0.00708KhPi  Pwf   r   Bo ln  e   0.75  s    rw  



2

Kh Pi  Pwf2

(oil)

(oil)



 r   1424ZT ln  e   0.75  s    rw  

(gas)

Similarly, the pesudosteady state for gases in horizontal wells would be. q



2

kh P  Pwf2



1424ZT ln(0.472re / rw  s  Dq

Where: D is the turbulence coefficient and is equal to D

6  10 5 K 0.1 h 2 rw h pef

Where h is the perforated section length in ft and  is gas specific gravity

The Well Inflow Quality Indicator (WIQI) is the ratio of the PI for an impaired to that for an undamaged well. PTA (pressure transient analysis) is preferable for determining skin. It can be difficult and costly.

Simple analyses such as these can qualitatively show how production rate can be increased if underbalanced drilling reduces skin. They may show that fewer wells are required and that the producible oil or gas in place can be increased. Abandonment pressure might be also reduced if the skin is reduced by drilling underbalanced. This is because of the pressure drop through the skin. Consider the additional pressure drop due to skin in oil well, for radial steady-state flow. Ps 

141.2QBo  s Kh

The following operating data of obayed horizontal gas well show such calculation in evaluating the effect of UBD in skin effect and in turn in the PI 

P=5900 psi



Pwf=3300 psi



Gas specific gravity=0.778



K=0.1 md



0.427re/rw=7



D=1.5E-3 (MSCF/d)-1



T=300 oF

87



h=14360 ft



Z=0.98



Visco.=0.027053 cp

S

Q (MMSCF)

PI (SCFD/psi)

0

170.98556 7.148225706 1

1

149.61637 6.254864998 0.8750234 88%

2

132.9951

5.55999581

5

99.75048

4.170170586 0.5833854 58%

10

70.414692 2.943758038 0.4118166 41%

100

11.188211 0.467734586 0.0654337 7%

180

8

160

7

WIQI

WIQI % 100%

0.7778148 78%

Production rate Well inflow quality indicator productivity index

6

120

5

100 4 80

PI WIQI

3

40 20 0 0

1

2

5

Skin factor

10

100

2

180

8

1

160

7

0

140

productivity index Well inflow quality indicator

6

120

5

100 4 80 3

60 40

2

20

1

0

0 0

88

Production rate

PI WIQI

60

Production rate

Production rate

140

1

2

5

10

100

Skin factor

FIGURE 12:VARIATION OF PI, PRODUCTION RATE AND WIQI WITH DRILLING INDUCED SKIN .

References 1. Medley, G.H., Stone, R.C., Colbert, W.J., and McGowen III, H.E.: Underbalanced Operations Manual, Signa Engineering Corp., Houston (1998). 2. Rehm, B.: Practical Underbalanced Drilling and Workover, Petroleum Extension Services, Austin (2002). 3. J. R. Duda, G. H. Medley, W. G. Deskins: “Strong Growth Projected for Underbalanced Drilling”, Oil & Gas Journal, (September 1996), 60-77. 4. J. Saponja, P. Eng.: “Challenge with Jointed Pipe Underbalanced Operations”, paper SPE37066 presented at the 1996 SPE International Conference on Horizontal Well Technology, Calgary, 18-20 November. 5. D.B. Bennion: “Underbalanced Drilling Technology Candidate Selection For Optimal Application”, JCPT, (November1994), 34-42. 6. D.B. Bennion, F.B. Thomas: “Underbalanced Drilling of Horizontal Wells: Does It Really Eliminate Formation Damage?”, paper SPE27352 presented at the 1994 7. SPE Intl. Symposium on Formation Damage Control, Lafayette, Louisiana, 7-10 February. 8. D.B. Bennion, F.B. Thomas: “Formation Damage and Horizontal Wells – A Productivity Killer?”, paper SPE37138 presented at the 1996 International Conference on Horizontal Well Technology, Calgary, Canada, 18-20 November. 9. D.B. Bennion, F.B. Thomas: “Low Permeability Gas Reservoirs and Formation Damage – Tricks and Traps”, paper SPE59753 presented at the 2000 SPE/CERI Gas Technology Symposium, Calgary, Canada, April 3-5. 10. R.A. Joseph: “Planning Lessens Problems, Gets Benefits of Underbalanced Drilling”, Oil & Gas Journal, (May 1995), 86-89. 11. Bennion, D.B.: “An Overview of Formation Damage Mechanisms Causing a Reduction in the Productivity and Injectivity of Oil and Gas Producing Formations,” JCPT, (November 2002), 41, 29-36. 12. Sharif, Q.: “A Case Study of Stuck Pipe Problems and Development of Statistical Models to Predict the Probability of Getting Stuck and IF Stuck, The Probability of Getting Free”, PhD dissertation Texas A&M University (1997). 13. Guo B., Galambor A.: Gas Volume Requirements for Underbalanced Drilling Deviated Holes, Petroleum Extension Services, Austin (2002).

89

90

Underbalanced drilling operations require some special surface equipment not normally used in rotary mud drilling operations. Shallow drilling operations usually have this specialized equipment incorporated into the single rotary drilling rig design. For the deeper drilling operations that use double and triple rotary drilling rigs, this specialized surface equipment is usually provided by underbalanced drilling equipment contractor. These contractors supply the rotary drilling contractor (the drilling rig) with the necessary surface equipment to convert the mud drilling rig to an air and gas or other drilling rig. The rotary drilling contractor and the air and gas drilling contractor are usually contracted by an operating Company.

Content 1-introduction 2- gas supply

3- gas compressors 4- in line facilities 5-Separation System 6 – pits and tanks

91

1. Introduction Most underbalanced drilling equipment is available on a rental basis from various air and gas drilling equipment contractors. These contractors supply the necessary surface equipment to carry out an UBD operation. The following sections discuss a typical gaseous drilling fluid equipment layout; detailed description of surface equipment designs for the other UBD fluids are beyond the scope of this manual.

2. Gas Supply While air is available by nature at each drilling location, supply of other gas sources such as nitrogen or natural gas requires specialized surface equipment.

2.1 Cryogenic Nitrogen The demand for nitrogen as a drilling fluid is met using either bottled gas, which severely limits volumes available, or liquid nitrogen delivered by ship, truck or pipeline. With these techniques, 100% nitrogen can be circulated down hole. If pipelines are not available, the only equipment normally needed for the use of cryogenic nitrogen onsite is a steady supply of nitrogen delivery trucks. The cryogenic nitrogen delivery system includes three main pieces of equipment mounted on a truck. A stainless-steel lined storage tank on a truck stores at approximately -320°F (-195°C) temperature; those tanks are available in a variety of sizes from about 2000 gallons to 7200 gallons. A cryogenic pump is also mounted on the truck as well as a vaporizer unit which heats the nitrogen from -320°F to about 80°F. This converts the nitrogen from liquid to a gas. The vaporizers allow variable temperature control to accurately maintain any desired pump rates. When nitrogen injection is required for only a short duration, cryogenic nitrogen will normally be more economical than other nitrogen generation techniques. Mobilization and manpower costs are much less when only a nitrogen truck is involved

92

FIGURE 1: CRYOGENIC NITORGEN

2.2 Membrane Generated Nitrogen The primary equipment requirement for on-site generation of nitrogen from ambient air is a Nitrogen Generating Unit (NGU). A NGU is a set of modules, each containing millions of hollow fiber membranes bundled together. The individual modules are encased in a steel housing. The modules can handle feed air injected using an air compressor, and must first pass through filters to remove as much particulate matter, oil and water as possible. Due to pressure losses through the membrane, a booster compressor may also be required at the NGU outlet to inject nitrogen downhole. Typical Nitrogen Generating Units have output capacities in the range of 800 to 3000 [scfm]. Hollow fiber membranes can produce nitrogen as pure as 99.9%. This would completely eliminate the danger of either downhole combustion or oxygen corrosion. However, flow rate through NGU‟s varies inversely with nitrogen purity; the purer the nitrogen, the lower the output volume of nitrogen. Consideration of the use of NGU‟s should account for location, job duration, volume of nitrogen required, the presence of natural gas contaminants and the nature of liquid phase of the drilling fluid. Each of the considerations above are logistical by nature, but significantly impacts the cost of the operation as well.

FIGURE 2: MEMBRANE SYSTEM

2.3 Natural Gas A unique gas source for gas or aerated fluid drilling is natural hydrocarbon gas. This source is typically only feasible when drilling in an area which has a readily available source of natural gas. Potential sources of natural gas are developed gas fields or nearby high pressure gas lines. When using methane or field gas as a source of drilling fluid, the setup will essentially be the same as that for compressed air, except that a standard compressor package will not be

93

required. Some means of controlling the injection rate should be provided. This can normally be the choke in the supply line.

3. Air Compression System Compressors used in UBD to provide pressured gas down hole so the Gases used for underbalanced Drilling  Air.  Cryogenic Nitrogen.  Membrane Nitrogen.  Engine Exhaust.  Natural gas.

3.1 Compressors As their name indicates, these are the primary means of compressing air to the Pressure required to circulate it round the well. Several different types of compressor units are available - rotary vane, straight lobe, reciprocating, and rotary screw. Of these, the reciprocating and rotary screw types are the most widely used for drilling applications.

94

FIGURE 3: COMPRESSOR TYPES

Compressor output is usually expressed in terms of the free volume that the output air would occupy under the prevailing input conditions. Delivery capacities of 750 to 1,000 cubic feet per minute (cfm) are common in oilfield applications. Compressor output is sometimes expressed in standard cubic feet per minute (scfm). This is the volume that the air delivered by the compressor in one minute would occupy under standard conditions of temperature and pressure (STP, 60°F and 14.7 psia). When expressed in scfm, the output decreases with increasing altitude and temperature because of the accompanying reduction in density of the free air drawn into the compressor. Assuming that air behaves as an ideal gas, the volume, VI, occupied by a given quantity of air at pressure, P 1 (psia), and temperature, T1 is related to the volume, VO, at standard pressure (14.7 psia) and temperature (60°F or 520°R) by:

Vt  Vo

14.7(T1  460) 520 P1

(E QUATION 1)

The air delivery rate, Q o expressed in scfm, can be found from the free air delivery rate, Q,(cfm), the ambient pressure, P (psia), and the temperature T( 0F), using:

Qo  Q

520 P1 14.7(T1  460)

(EQUATION 2)

The influence of reduced ambient pressure on air delivery rate, due to operating at high elevations, can be significant in some parts of the United States. T ABLE 1: PREDICTED BOTTOM HOLE ANNULAR AND STANDPIPE PRESSURES AT VERSUS PENETRATION RATES IN A 6,000 FOOT DRY, AIR DRILLED HOLE.

Penetration rate Ft / hr 0 30 60 120 180 240 300

Annular pressure psia Standpipe pressure Standpipe without nozzle pressure with nozzle 33 93 167 38 94 167 43 95 167 53 98 167 64 103 167 75 108 167 88 114 167

As a rule-of thumb, atmospheric pressure decreases by 0.5 psi for each 1,000 feet of elevation increase. In the Rocky Mountains, it is not unusual to have wells located at 6,000 feet above sea level, where the ambient pressure is around 11.8

95

psia. At this elevation, a compressor rated at 1,000 scfm free air delivery will deliver only 803 scfm, if the ambient temperature is 60°F. The influence of temperature on delivery rate is smaller, but not necessarily negligible. Considering the same well location, if the ambient air temperature is 100"F, the delivery rate will drop further to 745 scfm. The well site elevation and ambient temperature should therefore be considered when determining compressor requirements. Well site elevation can have a further impact on compressor output because of its effect on the power generated by the compressors diesel engine. Lyons, 1984, indicate that the power output of internal combustion engines decreases linearly with increasing altitude. A normally aspirated diesel engine will lose 22 percent of its sea-level power rating when operated at an altitude of 6,000 feet a turbo charged engine will lose approximately 15 percent of its power rating. This will be significant if the compressors are to be operated close to both their volumetric delivery and pressure ratings. Measurements of compressor delivery rates, made with an orifice meter during field operations, have indicated that the delivery rate actually achieved by different compressors can vary between 50 and 95 percent of rated capacity. A common average is 70 to 75 percent of the rated inlet capacity. The efficiency of the compressor is primarily a function of how well it has been maintained. As a result, it is not possible to determine the discharge volume simply by measuring the compressor rpm. An orifice meter is the only practical way to determine actual volumes delivered to the standpipe. Very often, two or more compressors are used to provide the required flow rate. Depending on the daily rent 11 rate for compressors, in comparison to the total daily drilling cost, there can be stages in having an extra compressor In site, in addition to those necessary to give the desired flow rate. In this way, one compressor can be pulled out of service for maintenance without impeding drilling Operations. Single stage compressors typically have a maximum discharge pressure of about 135 psi. Most compressors that are used for air drilling are multi-stage (usually twostage in the case of rotary screw compressors). These have maximum discharge pressures that range from 250 to 350 psi. In many instances, this pressure capacity is sufficient for dry air drilling. Air compressors are available which provide adequate air volumes along with portability. The most commonly used oil field air compressor is a positive displacement, double acting, reciprocating, two or three-stage type compressor. The number of compressors in a package will depend on the air volume required to drill hole efficiently. Generally, one air compressor available on today's market, for oil filed drilling will put out from 400 to 1200 cubic feet of air per minute at 300 to 320 psig maximum pressure.

96

3.2 Boosters Boosters are positive displacement compressors that take the exit volume of the compressors and compress it to a higher pressure. A booster is required if drilling pressures exceed the pressure capabilities of the compressors. The oilfield booster will increase pressure from about 300 psig to about 1500 psig. The booster is necessary insurance on an air drilling operation should hole trouble develop. Boosters are positive displacement compressors that provide high pressure air. They are designed to receive the volumetric air/gas flow from the compressor(s) and increase it to a higher pressure. If one booster cannot handle the pressure boost from several compressors, an additional booster can be added parallel. • Low pressure Boosters The low-pressure boosters are normally composed of a two cylinder, single or two-stage, double acting, reciprocating, inter-cooled and after-cooled, 7 1/2” x 5” pressure booster. The low-pressure booster is capable of boosting with an inlet pressure of 165 PSI. • The high-pressure booster It is normally a single cylinder, double-acting, reciprocating, after-cooled, 2.75” x 7” pressure booster. The high pressure booster needs an inlet pressure of 1400 psi and can boost up to a pressure of 4000 psia. The highpressure booster may be volume restricted and this will need to be confirmed with the equipment supplier.

97 FIGURE 4: LOW PRESSURE BOOSTER (1800 PSIA)

4. In-Lines facilities 4.1 Air/gas Line The line from the compressor to the standpipe should be large enough I diameter (usually 4”) to minimize frictional losses. It should have a pressure relief valve to guard against high pressures for the compressors and other equipment. It should also have a check valve to prevent air or fluids back flow to the compressor. The standpipe should have a pressure gauge, while the air line should have a connection to the Braden head for reverse circulation if necessary. The air header should also connect through a release, or blow down line, to the blooie line. This way the compressors do not have to be shut down or taken off line during connection. A three way valve or two standard valves may be used, and should be positioned so the rig crew can control air flow from the rig floor all times.

4.2 Bypass Blow Down The main air header connects a bypass and chokes to a muffler. When necessary to stop air injection, the bypass is opened and the main air header closed while the compressors are shut down. The bypass blow down should b equipped with a muffler, often called a blow down silencer or bypass muffler, to silence the discharged air.

4.3 Scrubber The scrubber removes excess water in the compressed air flowing the flow line. If the humidity of the atmospheric air is high, then as the air is compressed in the compressors much of the water will return to the liquid state. Dry air drilling operations require the removal of this water before the compressed air is injected into the well.

4.4 Solid injector Inject hole-drying powders into the wellbore to dry weeping water zones or to reduce friction in a deep hole. The endless chain and the belt type with pistons are most practical

4.5 Valves

98

Both manually and remotely operated valves are located along the flow line to the rig. These valves are usually the gate or ball type. These valves cannot be operated in a partially open position. The abrasive nature of the compressed air flow in the flow line would erode the gate or ball of the valve and render the valve ineffective in the closed position. At strategic locations along the flow line are check valves. These special mechanical valves allow compressed air flow in only one direction (toward the standpipe).

4.6 Gauges Each of the compressors is equipped with independent gauges to assess its operating performance. In addition to the compressor gauges are those placed along the flow line. A low pressure gauge is placed downstream of the primary compressors but upstream of the booster compressor. This gauge allows assessment of the performance of the primaries. A high pressure gauge is placed downstream of the booster compressor to assess the performance of the primaries and booster when high pressure compressed air is required. Pressure gauges are also placed upstream and downstream of the water injection pump and the solids injector. The Blooie line carries exhaust air/gas and cuttings to the flare pit. Recommended length and diameter are 300[ft] (100[m]) or more, with a cross sectional area equivalent to that of the annulus. The outlet end of the line should be crosswind to the prevailing wind and should extend past the flare pit wall by 6[ft]. The Blooie line should be securely anchored and grounded along its entire length.

5.1. Gas Sniffers It can be hooked into the blooie line to detect very small amounts of gas entering the return flow of air and cuttings from the annulus. The gas sniffer is located on the blooie line just after the return flow from the annulus enters the blooie line.

5.2. Deducter In order to minimize the dust exiting the Blooie line, a Deducter is employed to wet the cuttings slightly prior to their exit from the Blooie line. This accomplished using a small centrifugal pump, flexible water lines and some form of jet or spray nozzles inside the Blooie line.

5.3. Pilot Light

FIGURE 5: DEDUCTER

A small pilot light or flame should be maintained at the end of the Blooie line. This will ignite any gas encountered while drilling. When drilling with natural gas, the flame should be extinguished until full flow is available in the Blooie line.

99

5.4. Sample Catchers A “sample catcher” is installed on the blooie line to catch drill cutting samples. The sample catcher also serves a more important function; It allows observation of the dust when the de-duster is being used. This is necessary because, should the dust disappear, damp or wet down hole condition exists and trouble is pending or has already occurred This trouble comes in the form of down hole fires and/or a stuck drill string.

FIGURE 6: SAMPLE CATCHER

5.5. Burn Pit Positioned at the end of the Blooie line, the burn pit should be located away from the standard mud drilling reserve pit. The burn pit will prevent any hydrocarbon liquids from burning or flowing into the reserve pit, thus preventing a reserve pit fire near the rig.

100 FIGURE 7: BURN BIT LOCATION

5. Separation System In all underbalanced operations, the separation system that is to be used has to be tailored to the expected reservoir fluids. The separation system must be designed to handle the expected influx fluids and gasses, and it must be able to separate the drilling fluid from the return well flow in order for it to be pumped down the well once again. The surface separation system in underbalanced drilling can be readily 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, as the return flow is comprised of: Oil Water Gas Solids

The challenge for the separation equipment is to effectively and efficiently separate the various phases of the return fluid stream into their individual streams whilst at the same time returning a clean fluid back to the drilling process. The approach taken is largely dependent on the expected reservoir fluids. Normally the first approach is taken, but if erosion is expected to be a problem, the solids can be removed first. 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: Classification Operating Pressure Low pressure: 10 to 20 psi, up to 180 to 225 psi Medium pressure: 230 to 250 psi, up to 600 to 700 psi High-pressure: 750 to 5000 psi 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. Separators are classified as “two-phase” if they separate gas from the total liquid stream and “three phase” if they also separate the liquid stream into its crude oil and water components. In underbalanced drilling, the term “four-phase” separation is used to indicate the separation of 1) oil, 2) water, 3) gas and 4) solids. Horizontal and vertical separators can be used. Vertical separators are more effective when the returns are predominantly gas, while horizontal separators have higher and more efficient fluid handling capacities.

101

5.1 Horizontal separators In horizontal separators, well returns enter and are slowed by the velocityreducing baffles. Solids predominantly settle in the first compartment from where they can be removed by a solids transfer pump. Liquid passes over the partition plate into the second compartment where further solids separation takes place and the liquids begins to separate by virtue of their density difference and FIGURE 8: HORIZONTAL SEPARATOR residence time. The liquid spills over to the third compartment where separation is completed. The water component and liquid hydrocarbon are discharged from different levels of the third compartment. The separator should be fitted with adequately sized pressure relief valves and an emergency shutdown valve, triggered on high/low liquid level, and high and/or low pressure. It should be fitted with sight glasses to indicate liquid levels and observe the solids level.

5.2 Four-phase separator A separator used to process under balanced drilling returns will need to provide four phase separation of liquid hydrocarbon, water or aqueous drilling fluid, gases (both produced and injected), and cuttings. Typically, underbalanced drilling separators operate at 20 to 50 psig but they can be rated for 200 to 500 psi maximum pressure. Separating gases from the returns is only efficient if the separator pressure is low Additional degassing equipment may be necessary downstream of the primary separator – this will be discussed later in this section. Frequently, underbalanced drilling returns are produced in slug flow, with intermittent slugs of liquid at much higher instantaneous flow rates than the overall average liquid rate. These slugs can overwhelm a conventional separator. At the very least, the internal separator design will have to minimize "splashing" when a slug enters. Some underbalanced drilling separators have a spiraled entry baffle for this purpose. Using a higher vessel pressure will reduce the tendency for slug flow, but this will also decrease the efficiency of removing gas from the liquids.

102

FIGURE 9: FOUR -PHASE SEPARATOR

5.3 Degasser Gas carryover from the separator to an open mud pump suction tank is potentially dangerous, particularly if there is any possibility of H2S production. Gas in the reinjected liquid can cause lower than anticipated pressures downhole, with consequent higher production and safety concerns. It will also interfere with the efficiency of the mud pumps. All gas has to be eliminated from any liquid to be reinjected into the well. In most circumstances, it will be necessary to use an additional degasser, downstream of the primary separator.

5.4 Mud/Gas Separator A large, vertical mud/gas separator, with a height-adjustable support frame, is necessary for proper gas removal in the separator. This “open system,” or atmospheric-pressured vessel, should be at least 6 feet in diameter by 12 feet high, with sufficiently large gas flare lines (6- to 12-inch) and adequate liquid dump lines to handle the expected instantaneous flow rates. The flare stack, with variable height adjusters for different flow or location conditions, must be equipped with an automatic flare igniter system. In areas of high gas production, it is common to see a 50- to 100-foot high flare, concurrent with an annular pressure of 1,000 psi or more. This instantaneous production rate cannot be precisely calculated; rather it is empirically derived to be between the expected future production rate and the absolute open flow (AOF) rate of the formation.

103

FIGURE 10: MUD / GAS SEPARATOR WITH B AFFLES

6. Pits & tanks 6.1 Surge Tank A surge tank (or de-aerator) is required only in aerated fluid drilling. Its purpose is to prevent the air from blowing water or mud out of the system and onto the location, and to air separation for both, drilling liquid and cuttings from the gas phase. Back pressure control chokes at the surge tank help control the down hole pressures and surging. A huge variety of separators are available from simple systems to closed separators.

FIGURE 11: A CLOSED SYSTEM OF UBD TANKS

6.2 Skimmers Drilling fluid and oil flows from the gas separator into a series of two or more tanks The tanks have weirs or partitions at the top that allows the oil that rises to the top of the water to flow over into a second tank partition and then into the second tank. Then the third tank, etc. The water is pumped from the bottom of the tank. Thirty minutes to an hour of separation time is usually enough for free oil to separate from the water and rise to the surface With persistent oil/water emulsions, breakers may have to be sprayed or mixed into the first pit or pumped into the line between the separator and first skimming. Actually, the skimmer can be divided into two pits;

6.3 Drilling Fluid Pit 104

The drilling fluid pit serves as a reservoir for cleaned drilling fluid, which is automatically returned to the rig pit for mud pump suction. The drilling fluid pit contains two or more centrifugal pumps, with level controllers.

These maintain levels adequate to ensure proper gravity flow from the primary and secondary oil separation pits. Each centrifugal pump has its own level controller and acts independently, to maintain pit level regardless of the return flow from the well. Complete redundancy in these pumps is necessary, to ensure that the return flow of drilling fluid will not be interrupted during critical flow drilling periods.

6.4 Water Tank When the drilling fluid has an aqueous phase, water from the separator will be discharged into one or two settling tanks, before being transferred to the mud pump suction tank. Since additional solids separation occurs in these tanks, they should have sloped bottoms and be fitted with internal risers for water draw off, to provide the cleanest possible water to the mud pumps.

6.5 Solids Tank There should normally be a cuttings storage tank to receive solids discharged from the separator, unless the anticipated volume of cuttings is sufficiently low that the separator will only be emptied at the end of the job.

7. Flare system As hydrocarbons are produced whilst drilling underbalanced, these must be handled on the drilling location. Gas is normally flared whilst crude oil and condensate are stored and then pumped to a processing facility. Where environmental regulations preclude flaring, gas re-compression and export injection can now be considered as a viable alternative to flaring. Flaring is either done in a flare pit or through a flare stack. The flare stack or flare pit should be equipped with an automatic ignition system and flam propagation blocks. For safety reasons a great deal of consideration should be given to the surface equipment layout to avoid unnecessary rig crew exposure to noxious fumes, radiated heat, noise and flammable liquids.

Even with the use of water curtains as a means of preventing the spread of fire and thermal radiation, it is necessary to know the amount of thermal radiation that will be transmitted through the water curtains. For onshore systems a heat radiation survey can dictate the required height of the stack.

105

FIGURE 12: FLARE LOCATION

8. Surface Measurements It is convenient to divide UBD surface instrumentation into separate categories based on the equipment that it serves. The general problems of instrumentation are not unique to UBD but are common to all drilling. With UB drilling, there are several different service companies, the drilling contractor, and the operator on location. Each of them is collecting their own information, often in specific formats. To be really useable, the material has to be gathered into a standard format. On most drilling operations, the mud logger collects the drilling data, but with few exceptions, they do not maintain detailed operational data.

8.1 Air and Gas Drilling

106

In all operations where air, gas, or nitrogen is used, it is critical to measure the gas content and record the pressure and temperature. The metered gas should be reported as at local conditions, and as reduced to standard cubic feet or meters. Metering of air and gas is traditionally done with differential pressure Meters in a run with straightening vanes. Other systems using turbine or positive Displacement meters are available. Any system is satisfactory that is calibrated and Provable. Pressure is a critical part of gas drilling operations. Pressure, weight, and ROP are the driller's measurement tools. Rig mud pressure gauges are not adequate to measure gas pressures in the range and accuracy needed. The gauge must precise enough to register 10 to 20 psi change at 300 psi.

8.2 Foam Drilling Foam drilling input and output need to be carefully measured and compared against a computer model. Foam systems are used to maintain an underbalanced against the reservoir. Since foam is rheological a dynamic and complex mixture of gas and fluid, good measurements are needed to maintain balance in the system. The basic measuring systems used for air drilling need to be used with foam. The actual fluid and gas input need to be recorded in a parallel manner because a constant surface ratio is one of the requirements for a stable system. In foam drilling, manual pump stroke count are only marginally satisfactory. A low-pressure probe and recorder should be kept at the head of the flow line.

8.3 Aerated Fluids In simple open aerated mud or water systems, the pit volume and mud flow can be recorded by conventional pit volume recorders and a flow sensor in the flow line. The rig pressure gauge and pump stroke counters are adequate to measure mud rate. The air volume needs to be metered. The rotating head pressure (or the pressure just below the rotating head) further supplies back pressure and flow data.

9. Foam drilling accessories Foam Drilling is especially suitable for drilling large holes in formations that are prone to lost circulation. Foam is a gas liquid dispersion in which the liquid is the continuous phase and the gas is the discontinuous phase. The low density and high viscosity of foam at low shear rates make it extremely useful as a circulation medium in low pressure reservoirs. The consistency of foam is much like shaving cream. These properties minimize fluid loss to the formation and reduce required annular velocities yet provide high lifting capacity at minimum circulating pressures much better lifting capacity than that of a fluid. Foam can achieve bottom hole pressure equivalent to a circulating fluid weight in the range 0.2 to 0.8 sg

107

9.1 Foam Generator The one addition to a conventional air/mist drilling compressor system, for preformed foam drilling, is the foam generator. It ensures thorough mixing of the two phases. One type of foam generator is located where the gas and liquid flows meet. It introduces the liquid into the gas flow through a small bore tube centered in the gas flow path, and then directs the mixture through a venture type flow constriction. Other foam generators are located downstream from where the air and liquid flows meet. . These foam generators may contain baffle plates, or even sand beds, to promote mixing. In practice, it is not clear that a foam generator is specifically required. The air and liquid mixture will invariably flow through a number of valves and experience many changes in direction, before it enters the Kelly; these alone may produce a good foam. Even if foam does not form at the surface, it will when the mixture passes through the bit. There is evidence that foam generated at the surface is more tolerant of contaminants, such as formation water or hydrocarbons, than foam formed in their presence. Unless there are specific reasons not to do so, it makes sense to use a foam generator.

9.2 Foam pump types Many types of pump are suitable for use for foam injection purposes. The basic requirement is the ability to pump a slightly viscous, but clean, fluid up to the maximum pressure of the air compressor (nominally above 6 bar [100 psi]) at relatively low delivery volumes (1–20 liters/minute [.25 - 4 gallons/minute]). This will meet most foam drilling requirements. The following types of pump can be used:

9.2.1

Hand Pump

Semi rotary or piston „pressure testing‟ pump.

9.2.2

Barrel Type Pump

Air- or electric-powered typical product transfer pumps designed to work from standard 200-litre (45 gallon) drum.

108

9.2.3

Piston Pumps

Duplex or triplex high-pressure pumps – typically „water-pressure wash‟ duties. These are readily available as electric-, petrol-, or diesel-powered. The most significant attribute of any foam pump is being able to control the injection flow rate to just the minimum required – over-injecting does not often cause many problems other than wasting water and making more mess on the surface. In remote locations, where water is being carried long distances, it helps to conserve its use to the bare essentials.

9.2.4

Water Injection Pump

Unstable foam (mist) drilling operations require the injection of water into the compressed air flow before the air is injected into the well. The water injection pump injects water, chemical corrosion inhibitors, and liquid foamers into the compressed air flow line these skid mounted water injection pumps are used for the deep drilling operations. These pumps are capable of injecting up to 20 bbl/hr (at 42 gal/bbl) into the air or gas flow to the well. The smaller drilling rigs have on-board water injection pumps. These smaller rig water injection pumps have capabilities from 10 to 25 gal/min. The small water injection pump carries out the same objective on these smaller rigs as the skid mounted water pump for the larger double and triple drilling rigs. The injection of water and appropriate chemicals and foamer is a vital option for air and gas drilling operations. Very few air and gas drilling operations are carried out without some water, chemical additives, and foam producing additives being injected.

9.3 Foam inlet manifold A simple pipe manifold is required to allow injection of foam – standard fittings as found in most plumbers can be used. Both the foam pump and the compressor require protection from being back-filled with each other‟s medium by fitting nonreturnable valves. For low-velocity foam a suitable gate valve fitted to the air supply helps regulate the airflow to give the correct air/foam mix.

9.4 Mixing method In both foam drilling methods a good mixing method is to use two, or possibly even three, 200-litre (45- gallon) open-topped barrels. In each drum mix the required foam formula, first mixing the polymer (only for slow foam) arriving at a convenient volumetric addition for the required viscosity, 35–40 Marsh funnel seconds (i.e. – 1 liter jug of polymer powder = 40 sec mix in 200 liters of water). Allow time for this mixture to yield viscosity. Add the foam .5 to no more than 1.5% dilution i.e. 1-3 liters of liquid soap or drill foam to a 200-litre barrel at the last minute, using just a few stirs with a clean spade or shovel to mix. Use water as clean as possible to mix to prevent fines and dirt from damaging or blocking suction-line filters of the small parts and passages of the foam pump.

109

9.5 Adequate foam supply Use the first barrel until empty and then switch the foam pump suction to the second barrel. While using this barrel, re-mix the first barrel. In this way, it will be possible to have a continuous foam supply available to the drilling operation. High foam consumption might dictate introducing a third barrel into the system to ensure that a mixed barrel of fully "yielded" polymer is always available.

FIGURE 13: TYPICAL FOAM DRILLING METHOD

FIGURE 14: RECYCLABE FOAM SYSTEM

110

10. Surface equipment layout for different UBD techniques 10.1 Air (dust drilling)

FIGURE 15: LAYOUT OF AIR DRILLING EQUIPMENTS

10.2 Mist or foam drilling

111

FIGURE 16: LAYOUT OF MIST OR FOAM DRILLING EQUIPMENTS

10.3 Aerated fluid drilling layout

FIGURE 17: LAYOUT OF AREATED FLUID DRILLING EQUIPMENT

10.4 Closed loop layout

112 FIGURE 18: CLOSED LOOP CIRCULATION SYSTEM

10.5 Mud cap drilling layout

FIGURE 19: LAYOUT OF MCD EQUIPMENTS

10.6 Flow drilling layout

113

FIGURE 20: FLOW DRILLING EQUIPMENT (EXAMPLE)

11. IADC UNDERBALANCED OPERATION COMMITTEE (Fluids Subcommittee - Equipment Requirements)

114

Fluid Group

Fluid

Equipment Requirements

Gas Drilling

Air

Compressors, boosters, mist/foamer pump, blooie line, rotating head/diverter, flare/flame, drill string floats

Nitrogen

Cryogen tanks & heaters - OR - membrane nitrogen generators, boosters, mist/foamer pump, blooie line, rotating head/diverter, flare/flame, drill string floats

Natural Gas

Pipeline / gas source, compressors, boosters, mist/foamer pump, blooie line, rotating head/diverter, flare/flame, drill string floats

Mist Drilling

Mist

Source of gas, small injection pump, compressors, boosters, mist/foamer pump, blooie line, rotating head/diverter, flare/flame, drill string floats

Foam Drilling

Dry Foam Source of gas, compressors, boosters, foam generator, blooie line, rotating head/diverter, flare/flame, special metering equipment, defoaming tank and pump, drill string floats

Gasified Liquid Drilling

Gasified Liquid

Gas/liquid separator, compressors, boosters, flare line, rotating head/diverter, flare/flame, drill string floats

Liquid Drilling

Oil Based

Rotating head/diverter, drill string floats, cuttings disposal

Emulsion

Rotating head/diverter, drill string floats, cuttings disposal

Water Based

Rotating head/diverter, drill string floats

NOTES: 

Snubbing unit, coiled tubing unit, casing drilling, parasitic strings, and closed loop systems may be required.



Hydrogen Sulfide (H2S) production requires special considerations.



Gas and H2S monitoring systems, confined space, explosion-proof electrical equipment, electrical bonding/grounding, and wind socks should be considered.



Depending on fluids used and production: 2-phase or 3-phase separators (vertical or horizontal) may be required.



Additional lighting, fire fighting equipment, and power generation may be required.



Special data acquisition systems should be considered.



If crude oil is being considered as the UBD fluid, a HAZOP risk assessment is required.

115

12. OBAYED FIELD SITE DRAWINGS & EQUIPMENTS 12.1 Obayed P & ID

116

12.2 FIGURE 21: LAYOUT OF SURFACE EQUIPMENT IN OBAYED FILELD

General rig arrangement

117 FIGURE 22: GENERAL RIG ARRANGEMENT

118 FIGURE 23: LAY OUT OF SURFACE EQUIPMENT




119

DOWNHOLE EQUIPEMENT IN UNDERBALANCED DRILLING

120 D O W EN H O L E EQ UI P E MEN T IN UN D ER B A L AN C ED

IN Underbalanced Drilling

A

ir and gas drilling operations require some special

subsurface equipment and drilling methods that are not normally used in rotary mud drilling operations. Deep direct circulation operations use rotary drill strings that are similar to those used in mud drilling. But even these drill strings are equipped with downhole tools unique to air and gas drilling operations. Drill string design for an air drilled hole is very similar to that for a mud drilled hole. The drill string still consists primarily of drill pipe and drill collars. Stabilizers, reamers, jars and shock subs can still be used in an air hole. There are a few subtle differences. These are discussed in the following

Contents

DOWEN HOLE EQUIPEMENT IN UNDERBALANCED DRILLING

Down-hole Equipment

1. Rotary standard drill string 2. Drilling bits 3. Air hammer bits 4. Bottom hole accessories 5. downhole motors

6. Measurement while drilling 7. Electromagnetic measurement while drilling 8. Down hole motor 9. heavy weight drillpipe

121

Rotary Drill String There are two general types of drill strings used in air and gas drilling operations. The standard drill string discussed below is used almost exclusively for deep direct circulation operations. The dual wall pipe drill string is used exclusively for intermediate and shallow depth reverse circulation operations.

D O W EN H O L E EQ UI P E MEN T IN UN D ER B A L AN C ED

1. Standard drill string A drill string would be used on large drilling rigs. At the bottom of the drill string is the drill bit. The drill bit is threaded to a bit sub. The drill bit has a male thread or threaded pin pointing up. The bit sub is a short thick wall pipe that has a female thread or threaded box on both ends.

FIGURE 1: SCHEMATIC DRILL STRING

122

Above the bit sub are the drill collars. Each of the drill collars and most of the remainder of the components in the drill string are designed with a threaded pin down and a threaded box up.

Figure2:slick, spiral and non-magnetic drill collers

Generally the drill collars in a drill string have the same thread design. Above the drill collars are the drill pipe joints. The threads of the drill collar connections are usually not the same as the threads of the drill pipe joint connections (tool joints). Therefore, a special crossover sub must be used to mate the drill collars to the drill pipe. The crossover sub is a short thick walled pipe with a threaded pin down (with the drill collar threads) and a threaded box up (with the drill pipe threads).


The bit sub is used to protect the bottom threads of the bottom drill collar from the wear caused by the frequent drill bit changes that are typical for all deep drilling operations. A drill collar is a thick wall pipe that provides the weight or vertical axial force on the drill bit allowing the drill bit to be advanced as it is rotated. Usually there are a number of drill collars in a drill string. The number of drill collars in a drill string depends on how much weight-on-bit (WOB) is required to allow the drill bit to be advanced efficiently.

123 FIGURE 3 DRILL COLLERS AND HEAVY WEIGHT DRILL PIPES


At the top of the drill pipe section is the Kelly cock (or saver) sub. The Kelly cock sub is another crossover sub. But this sub is used to protect the bottom threads of the Kelly.

FIGURE 4: KELLY COKE

2. Dual Wall Pipe Drill String: Intermediate and shallow depth large diameter wells can be drilled with direct circulation techniques. But reverse circulation techniques are more efficient and are the preferred techniques. The drilling industry has developed some very unique down hole tools for reverse circulation air drilling operations Reverse circulation techniques are not restricted to air drilling operations. Reverse circulation techniques often use standard drill string like that

124 FIGURE 5:DUAL W ALL P IPE DRILL S TRING

Drilling Bits There are three basic types of rotary drill bits. These are drag bits, roller cutter bits, and air hammer bits .

FIGURE 6:

TYPES OF DRILL BITS

bits Fixed Cutter Bits Natural Diamond Insert

PDC Insert

TSP


Rotary dual wall pipe reverse circulation operations must be used on drilling rigs equipped with hydraulic rotary top drive systems (for single drilling rigs) or with hydraulic power swivel systems (for double and triple drilling rigs) to rotate the drill string. Dual wall pipe is quite rigid and has a much higher weight per unit length than standard single wall drill pipe. Thus, dual wall pipe can be used like drill collars (the lower portion of the drill string can be placed in compression).

Roller Cone Bits

Steel Mill

Tungsten Carbide Inserts

125

1. Drag Bits (fixed cutter blades)


Drag bits have fixed cutter blades or elements that are integral with the body of the bit. The earliest drag bits were simply steel cutter blades rigidly attached to a steel body that is made up to the bottom of the drill string. Later natural diamonds were used as the cutter elements. A diamond drill bit has natural diamonds that are embedded in a tungsten carbide matrix body that is made up to the bottom of the drill string. The most recent development in drag bit technology is the polycrystalline diamond compact (PDC) bit.

FIGURE 7: ANATOMY OF DRAG BIT

126 Steel Body

Matrix Body

Dual Diameter

1.1 Diamond Bits     

natural diamonds plow the rock to fail it proper selection of the bit for the formation direct understanding of the formation for bit style, diamond size, and diamond quality the harder the formation the easier it is to clean a diamond bit expected performance is referenced to roller cone offset

Special features     

low pressure drop for PDM and Turbine applications shallow cone, short gauge used for sidetracking with PDMs and Turbines deep cone enhances bit stability core ejector diamond bits

Natural Diamond Bits The hardness and wear resistance of diamond made it an obvious material to be used for a drilling bit. The diamond bit is really a type of drag bit since it has no movingcones and operates as a single unit. Industrial diamonds have been used for many years in drill bits and in core heads The cutting action of a diamond bit is achieved by scraping away the rock. The diamonds are set in a specially designed pattern and bonded into a matrix material set on a steel body. Despite its high wear resistance diamond is sensitive to shock and vibration and therefore great care must be taken when running a diamond bit. Effective fluid circulation across the face of the bit is also very important to prevent overheating of the diamonds and matrix material and to prevent the face of the bit becoming smeared with the rock cuttings (bit balling). The major disadvantage of diamond bits is their cost (sometimes 10 times more expensive than a similar sized rock bit). There is also no guarantee that these bits will achieve a higher ROP than a correctly selected roller cone bit in the same formation. They are however cost effective when drilling formations where long rotating hours (200-300 hours per bit) are required. Since diamond bits have no moving parts they tend to last longer than roller cone bits and can be used for extremely long bit runs. This results in a reduction in the number of round trips and offsets the capital cost of the bit. This is especially important in areas where operating costs are high (e.g. offshore drilling). In addition, the diamonds of a diamond bit can be extracted, so that a used bit does have some salvage value


Applications

127


Impregnated

Impregnated with GHI’s FIGURE 8: NATURAL DIAMOND

1.2 PDC Bits A new generation of diamond bits known as polycrystalline diamond compact (PDC) bits were introduced in the 1980’s These bits have the same advantages and disadvantages as natural diamond bits but use small discs of synthetic diamond to provide the scraping cutting surface. The small discs may be manufactured in any size and shape and are not sensitive to failure along cleavage planes as with natural diamond. PDC bits have been run very successfully in many areas around the world. They have been particularly successful (long bit runs and high ROP) when run in combination with turbo drills and oil based mud.

SHORT PDC BIT

MEDIUM PDC BIT

LONG PDC BIT

NATURAL DIAMOND BIT

TSP BIT

FIGURE 9:P OLYCRYSTALLINE C OMPACT (PDC) B ITS

128

1.3 TSP Bits Thermally Stable Polycrystalline (TSP) diamond bits. These bits are manufactured in a similar fashion to PDC bits but are tolerant of much higher temperatures than PDC bits.

Roller cutter bits use a crushing action to remove rock from the cutting face and advance the drill bit. The weight or axial force that is applied to the drill bit is transferred to the tooth or teeth on the bit. These teeth are pointed (mill tooth bit) or rounded (insert tooth bit) and the force applied is sufficient to fail the rock in shear and tension and cause particles of the rock to separate from the cutting face. The drill bits are designed to remove a layer of rock with each successive rotation of the bit. Roller cone bits (or rock bits) are still the most common type of bit used world wide. The cutting action is provided by cones which have either steel teeth or tungsten carbide inserts. These cones rotate on the bottom of the hole and drill hole predominantly with a grinding and chipping action. Rock bits are classified as milled tooth bits or insert bits depending on the cutting surface on the cones The major advances in rock bit design since the introduction of the Hughes rock bit include:  Improved cleaning action by using jet nozzles  Using tungsten carbide for hardfacing and gauge protection  Introduction of sealed bearings to prevent the mud causing premature failure  due to abrasion and corrosion of the bearings.

FIGURE 10:M ILLED TOOTH BIT


2. Roller Cone Bits

FIGURE 11: I NSERT BIT

129


Bottom Hole Profile

PDC

ROLLER CONE

Elements of a Rock Bit

130 FIGURE 12: ANATOMY OF CONE BIT

The Conical insert is used primarily in Medium/Medium- Hard rock. It is designated in the bit nomenclature with a suffix of C.

The Chisel insert is used in Soft/Medium-Soft rock. It is the standard insert in soft bits (40’s & 50’s) and has no suffix in the bit nomenclature.

The Trimmer is used specifically in the MAG product line. It enhances the gage rows ability to cut the bore hole wall. The MAG feature is used in Soft to Medium brittle rock formations.

The Give insert is used in areas were the aggressiveness of the conical insert is required with additional toughness. The Give is designated as a G in the bit nomenclature.

The Super-Scoop is used in very soft rock. With the patented offset tip, digging and gouging help penetrate in sticky materials. The Super-

The Ovoid is use in the hardest formations. Its blunt geometry gives it the most fracture resistant design. The ovoid is the standard insert in hard bits (60’s, 70’s & 80’s) and has no suffix in the bit nomenclature.

FIGURE 13: TOOTH PROFILE OF ROLLER CONE

3. Air Hammer Bits Percussion air hammers have been used for decades in shallow air drilling operations. These shallow operations have been directed at the drilling of water wells, monitoring wells, geotechnical boreholes, and mining boreholes. In the past decade, however, the percussion air hammers have seen increasing use in drilling deep oil and natural gas wells. Percussion air hammers have a distinct advantage over roller cutter bits in drilling abrasive, hard rock formations


Inserts tooth assembly

131 FIGURE 14: AIR HUMMER BITS


To prevent the air hammer from coming unscrewed while going in the hole, make each connection up drill collar tight. Also, the air hammer should be tested on the rig floor, using the air volume normally used for drilling. Note the pressure at which the air hammer operates at the normal drilling air volume. This will allow any malfunction in the operation of the air hammer to be detected while drilling. The operation of the air hammer should be checked periodically. Stop drilling, leave weight on the bit and air in the hole, place a steel object against the Kelly and near the ear and listen; a faint buzzing sound will be heard if the air hammer is working properly. Air hammer manufactures recommend pouring a small amount of oil down the drill pipe periodically to lubricate the moving parts of the air hammer. With proper care and handling, an air hammer can run 150 to 300 hours. Hammer Designs  

Conventional Air Hammers New Oilfield Air Hammer FAM-Us

Economics of Bit Applications  The cost of the bit is not the concern!  Performance is more important  projected ROP  projected footage  Relevant cost parameter is “Cost per Foot”  daily operations cost  trip time  bit cost

Cost per Foot (CPF) CPF = bit cost + rig rate (rotating hours + trip hours) / footage drilled

CPF 

132

B  R(T  t ) F

Where  bit cost, B, is in dollars  rig rate, R, is in dollars per hour  rotating time, T, and trip time, t, are in hours  footage drilled, F, is measured in feet

Drilling jars

The use of drilling jars in underbalanced drilling with jointed pipe is not a straightforward decision. In underbalanced drilling, drilling jars can be used and they are just as effective as in overbalanced drilling. Differential sticking does not occur during underbalanced drilling. The one issue with jars that needs to be considered is tripping jars using a snubbing unit. Drilling Jars The purpose of these tools is to deliver a sharp blow to free the pipe if it becomes stuck in the hole. Hydraulic jars are activated by a straight pull and give an upward blow. Mechanical jars are preset at surface to operate when a given compression load is applied and give a downward blow. Jars are usually positioned at the top of the drill collars.


A mechanical device used down hole to deliver an impact load to another down hole component, especially when that component is stuck. There are two primary types, hydraulic and mechanical jars.

FIGURE 15: MECHANICAL AND HYDROLIC JARS

133

Stabilizers


Stabilizers and rolling cutter reamers are special thick-walled drill collar subs that are placed in the BHA to force the drill collars to rotate at or near the center of the borehole. By keeping the drill collars at or near the center of the borehole the drill bit will drill on a nearly straight course projected by the center axis of the rigid BHA. Stabilizers and rolling cutter reamers have blades or rolling cutters that protrude from the sub wall into the annulus to near the borehole diameter. The space between blades or rolling cutters allows the air or natural gas flow with entrained rock cuttings to return to the surface nearly unobstructed.

FIGURE 16: STABLIZERS

Reamers The rolling cutter reamer is a special type of stabilizer tool that provides “blades,” which are cylindrical roller cutter elements that can crush and remove rock from the borehole wall as the drill bit is advanced. Often the reamer is placed just above the drill bit. Reamers are available in a three-point rolling cutter reamer as shown in figure (A) These reamers have the roller cutters 120 0 apart on the circumference and are also available in a four-point rolling cutter reamer where These reamers have the rolling cutters 90_ apart on the circumference such rolling cutter reamers are used when drilling in abrasive, hard rock formations

134 FIGURE 17: REAMERS

Shock Sub



Mechanical shock sub



Hydraulic shock sub

Figure 18: Mechanical &HYDROLIC shock SUB

Bottom hole assembly The BHA is the section of the drill string below the drill pipe. This section of the drill string is the most rigid length of the string. It determines how much weight can be placed on the drill bit and how “straight” a vertical borehole will be drilled with the drill string. It is composed of a drill bit at the bottom, drill collar tubular, a near bit stabilizer directly above the bit, a stabilizer at the middle of the assembly, and a stabilizer at the top of the assembly. The addition of stabilizers to the drill collar string generally improves the straight drilling capability of the drill String.

In general, air drilled boreholes can have more deviation than mud drilled boreholes (assuming same rock formations). However, most of the increased deviation from vertical is due to the fact that air drilling penetration rates are significantly higher than a mud drilling operation and drillers tend to take advantage of that increased drilling rate and let the deviation get away from them. To correct this tendency, it is good practice to utilize a more stabilized BHA when drilling an air drilled borehole than would be used in a comparable mud drilled borehole.

FIGURE 19: STANDARD BHA FOR MOST AIR HAMMAR OPER ATION


A shock sub is normally located above the bit to reduce the stress due to bouncing when the bit is drilling through hard rock. The shock sub absorbs the vertical vibration either by using a strong steel spring, or a resilient rubber element There are two types of shock subs:

135


Down hole motor The main issue with motors arises when drillstring gas injection is used and a compressible mixture drives the motor or turbine. Gas will increase the speed of the motor but will decrease the torque output from the motor. Multiphase fluids will reduce the operating window of a motor or turbine. One of the major problems with motors in compressible fluids is the ability to detect a motor stall. When pumping a compressible fluid during a motor stall, the pressure increase will be masked by the gas compressibility. Once the driller notices that the motor has stalled he will pick up off bottom. This often results in the gas pressure being released from the drill string and the result is that the motor will exceed its maximum flow rate and overspeed, causing damage. Down hole motors designed for the use with a conventional drilling fluid as a power source, for lubrication and for heat dissipation have limitations when used with air, mist or foam as the circulating medium. Because of the lower drill cuttings lifting capacity of air, mist and foam, much higher volumes have to be circulated to allow for adequate hole cleaning. These high flow rates can result in premature tool failure

FIGURE 20:D OWN HOLE MOTOR

136

Measurment while drilling (MWD)

The most common technique for transmitting MWD data uses the drilling fluid pumped down through the drill string as a transmission medium. Mud-pulse telemetry transmits data to the surface by modifying the flow of mud in the drillpipe in such a way that there will be changes in fluid pressure at surface. It involves the sequential operation of a down hole mechanism to selectively vary or modulate the dynamic flowing pressure in the drillstring and thereby sends the real-time data gathered by the down hole 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 down-hole sensors.


As directional drilling has become commonplace, so has the industry’s need for cost-effective, measurement-while-drilling (MWD) systems that can deliver accurate directional survey and toolface data in all types of drilling environments.

FIGURE 22: MWD SCHEMTIC

137 Figure 21: MWD components

Electromagnetic MWD


Electromagnetic telemetry transmits data to the surface by pulsing low-frequency waves through the earth. There are essentially two ways of doing this: one that induces an axially symmetric electric field around the drill-pipe, and a second that drives current directly from one part of the drill-pipe to another. The former is referred to as “Imag” and the latter as “Emag”.

Imag transmission is typically used for short-hop systems, e.g. across a motor. It has an advantage in that its transmission is essentially independent of mud properties and layering within the rock formation. Signals are generated by wrapping solenoid coils around the drillpipe to create a magnetic dipole. The contrast in magnetic properties of metal versus rock is only about 100 to 1, but the dipole efficiency can be increased somewhat by adding ferrite cores to the coils.

Emag transmission is typically used to send data over longer distances. Signals are generated from a voltage difference on the drill-collar, which is either induced from toroidal coils wrapped around the collar or created directly by adding an insulating “gap” to the drillpipe. This creates an electric dipole with one long end (to the surface) and one “short” end (to the bit). The metal drillpipe acts as a long focusing antenna because of the large conductivity contrast between it and the rock (10,000,000 to 1).

138 FIGURE 23: ELECTROMAGNETIC MEASUREMENT WHILE DRILLING

Pressure while drilling sensors have proved invaluable in every underbalanced drilling operation to date where 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 underbalanced drilling. Adding a down hole gauge or sensor in the drillstring will definitely enhance the underbalanced drilling operation and help the team optimize the drilling process and increase the knowledge of the reservoir.

FIGURE 24: MPD STRING

Heavy weight drill pipe Heavyweight drill pipe is an intermediate weight per unit length drill string element. This type of drill pipe has a heavy wall pipe body with attached extra length tool joints. Heavyweight drill pipe has the approximate outside dimensions of standard drill pipe to allow easy handling on the drill rig. The unique characteristic of this type of drill pipe is that it can be run in compression in the same manner as drill collars. Heavyweight drill pipe elements are used in a number of applications in rotary drilling. Because this drill pipe can be used in compression, this drill pipe can be used in place of drill collars in shallow wells with small single or double rotary drilling rigs. This drill pipe is also used in conventional drill string for vertical drilling operations as transitional stiffness elements between the stiff drill collars and the very limber drill pipe. Their use as transitional stiffness elements reduces the mechanical failures in the bottom drill pipe elements of the drill string


Pressure While Drilling (PWD)

Heavyweight drill pipe is used in directional drilling operations where drill collars can be replaced by the heavyweight pipe. Using heavyweight drill pipe in place of drill collars reduces the rotary torque and drag and increases directional control.

139


140

FIGURE 25: H EAVY WEIGHT DRILL PIPE

Float valves These are also known as non return valves. Non return valves are necessary for underbalanced drilling to prevent influx of reservoir fluids up inside the drillstring either when tripping or making connections. It must be recognized that there is pressure below non-return valves. The positions of the float valve in the drillstring depend on the tools in the BHA and the policy of the operating philosophy underpinning the safety management of the operation. The number of float valves in the BHA and the drillstring is also a matter of company policy consistent with perceived risks and management thereof. Using a float valve is another primary difference between drilling with air and with fluid. It is not common to run a float valve when drilling with fluid. A float valve is a requirement when drilling with air. In an air hole, the drillstring should not be run without a float valve near the bit. Air in the annulus contains cuttings, making it much more dense than the air inside the drillstring. When air is vented from the drillstring to make a connection, air and cuttings will U-tube into the drillstring from the annulus. As the differential pressures equalize, air will stop moving and the cuttings will fall to the bottom. Inside the drillstring, the cuttings will settle on top of the bit and plug the drillstring. The pipe will most likely have to be tripped out of the hole in order to unplug the drill string. Installing a float valve above the bit eliminates the possibility of plugging the drill string with cuttings while bleeding pressure off the drill string.

While the best place for the float valve is immediately above the bit, sometimes it may have to be run immediately above a down hole tool (such as a motor, MWD tool or stabilizer). 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.

dart type

Float valves

Flapper type

There are two types of float valves; these two types are the dart type and the flapper Type. The dart type valve is spring activated, which opens to allow the direct circulation flow to pass around the dart. This type of valve provides a more secure shutoff against high and low pressure back flows. The flapper type valve opens fully during circulation to provide an unrestricted bore through the valve and closes when back flow pressure is applied. These valves are used in nearly all deep rotary air and gas drilling operations. The dart valve is used in the bit sub just above the drill bit. In practice, at least one flapper valve is placed just above the drill collars or above a down hole motor. A second is often placed about 1000 ft. below the surface. It is not unusual for a long drill string to have three or four float valves.


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.

141 FIGURE 26: THE DART TYPE AND THE FLAPPER T YPE


The fire stop is a special type of flapper valve. It is essentially an upside-down float valve. It is usually placed just above the drill bit. These valves have a zinc ring that holds back a spring-loaded flapper mechanism to allow the compressed air or gas to be circulated directly from the surface through the inside of the drill string. Wire line equipment can be run through these valves when the fire stop is in the normal open position. In the event of a down hole fire, the zinc element melts, releasing the spring-loaded flapper. This shuts down the flow of air or gas into the bottom of the well, thus shutting off the source of fuel for the fire. Fire stop valves are rarely used in present drilling operations. String floats can hinder wire line operations such as inclination surveys. The string float can cause the survey tool to become stuck in the hole. The survey tool is heavy enough to open the flapper style float and pass through it. When the survey tool is pulled from the hole, the float is held partially open by the wire line but it is not open enough to pass the tool. The survey tool will encounter the flapper and push it closed, causing the tool to become stuck. To prevent problems with surveying, the string float is usually tripped out of the hole, laid down and the drill string is run back to bottom before surveying. After surveying, the string float is reinstalled in the drill string near the surface and drilling continues until the next survey. Each time the well is surveyed, the string float is tripped out of the hole

Wire line Retrievable Float Valves Wire line retrievable float valves are normally run in the upper section of the drill string. The purpose of the wire line retrievable valve is to allow the gas in the drill string to be bled off rapidly and allow connections to be made. The valve prevents the entire drill string gas volume having to be bled off every connection and the valve also adds another well control barrier to the upper part of the drill string.

FIGURE 27:WIRE LINE R ETRIEVABLE FLOAT V ALVES

The valve can be retrieved if wire line operations through the drill string are required or if the valve has to be moved to a higher position in the string. The valves are positioned in a locking profile sub that is part of the drill string.

142

Down Hole Isolation Valves

In underbalanced drilling, there are a number of options when tripping the string. The well can be allowed to flow, the well is shut in and a snubbing unit is used to trip the pipe, or the well is killed and tripping is conducted overbalanced. Killing the well is not an option if reservoir productivity improvement is the objective for underbalanced drilling. To avoid the use of a snubbing unit, two types of down hole isolation valves have been developed. The down hole valve or 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 drill string, 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. Now the drill string can be tripped out of the well without the use of a snubbing unit and at conventional tripping speeds, thus reducing rig time requirements and providing improved personnel safety. The drill string can then be tripped back into the well until the bit is just above the deployment valve, at that point the pressures are equalized and the valve can be opened and the drill string run in to continue drilling operations.


The down hole deployment or down hole isolation valves have been designed to eliminate the need for snubbing operations, or the need to kill the well in order to trip the drill string during underbalanced drilling operations.

143 FIGURE 28: D OWN H OLE ISOLATION VALVES

Drill pipe


Conventional drill pipe can be used in underbalanced drilling operations. Torque and drag friction factors in underbalanced drilling are often double of what they are in overbalanced drilling operations. So more torque is required to turn the pipe and this has a direct impact on the connections as well as on the maximum reach with the given surface equipment.

144

It is also important that drill pipe being used for underbalanced drilling not be plastic coated. In a gasified fluid, the plastic coating is likely to be stripped off and plug the string. The new abrasion-resistant, liquid-applied, modified epoxyphenolic or the ceramic particle loaded epoxy resin coated systems for drill pipe can be used for underbalanced drilling operations. Hard banding: Any hard banding on the drill pipe must be reviewed carefully. Hard banding on the Pipe will wear out the rotating diverter rubbers much more quickly than pipe without hard banding. If hard banding is required, then it must be as smooth as it can be. Drill pipe Rubbers Drill pipe protection rubbers cannot be run when drilling underbalanced. There are two reasons for this. 1- They suffer from gas impregnation when run deeper into the well and will explosively de-compress when pulling out of the hole. 2- Is running the drill pipe rubbers through the rotating diverter will cause blow-by when tripping and drilling.

FIGURE 29: DRILL PIPE

References o API Recommended Practices for Drill String Design and Operating Limits, API RP7G, Sixteenth Edition, August1998.

o Drilling Assembly Handbook, Smith Services, Division of Smith International, 2006. o Roscoe Moss Company, Handbook of Ground Water Development, Wiley, 1990. o Bourgoyne, A. T., Millheim, K. K., Chenevert, M. E., and Young, F. S., Applied Drilling Engineering, SPE, First Printing, 1986. o Durrett, E., “Rock Bit Identification Simplified by IADC Action,” Oil and Gas Journal, Vol. 76, May 22, 1972. o Wilson G. E. (1979) "How to Select Bottomhole Drilling Assemblies". Petroleum Engineering International. March Issue.


o Drilling Manual, International Association of Drilling Contractors (IADC), Eleventh Edition, 1992.

145

146

Coiled Tubing is a service used for Well Intervention in the Oil, Gas, and Geothermal industries. It is widely accepted as one of the Safest, fastest, and most economical means of performing well stimulation, work over, and drilling operations.

Contents 1- Origin of coiled tubing 2- Coiled tubing equipment 3- Surface equipment 4- Downhole equipment 5- Coiled tubing drilling 6- Coiled tubing perforation

147

Introduction: Coiled Tubing is a service used for Well Intervention in the Oil, Gas, and Geothermal industries. It is widely accepted as one of the Safest, fastest, and most economical means of performing well stimulation, work over, and drilling operations. Well Intervention technique using continuous length of thin-walled tube into pressurized well by means of a mechanically driven belt. Its Common sizes range from 1” - 1¾” due to current economic changes & CT advance technology larger size range from 2” - 3½”. Coiled tubing is manufactured from low carbon steel that has both strength and ductility where:  Strength: is to bear its own weight and that of down hole tools in the well.  Ductility: it can wrap around the reel and gooseneck. The alloy used has very low sulfur content to make it resist attack of H2S, Chromium, Copper, Nickel to give it ductility. It can be easily transported, rigged up & unrigged in a shortest period of time. (Offshore - 3 hrs & Onshore - 1½ hrs). Currently max working depth 25K ft at 250 ft/min. CT is cheaper & quicker alternative to perform down hole works compare to conventional methods. CT, as a well service tool, was originally developed in the early 1960’s and has become a key Component of many well service and work over operations. Well service or work over applications still account for over three-quarters of CT work. However, the recent and more advanced Use of CT technology for completion and drilling applications is rapidly gaining popularity.

148

FIGURE 1: C OILED TUBING TECHNOLOGY

What is coiled tubing? CT as a device is hydraulically powered service system which is designed to inject and retrieve a continuous string of tubing. CT as a string is continuous Lengths of tubular small diameter steel pipes spooled onto a take-up reel. The tube is nominally straightened prior to being inserted into the wellbore and is recoiled for spooling back onto the reel.

FIGURE 2:THE MAIN COMPONENT OF CT UNIT

Features of CT technology: Speed and economy are key advantages of applying CT technology. Also, the relatively small Unit size and short rig-up time compare favorably with other well drilling and work over Options. Beneficial features of CT technology include the following: • • • • • • •

Safe and efficient live well intervention. Capability for rapid mobilization, rig-up, and well site preparation. Ability to circulate while RIH/POOH. Reduced trip time, hence less production downtime. Lower environmental impact and risk. Reduced crew/personnel requirements. Relatively low cost.

149

Uses of coiled tubing in oil industry: A. Drilling: It is used for directional and non-directional drilling. Can drill more than 3100ft in 19 hr where No pressure surge & rapid drilling in pay zone. B. Used in perforation: The flexibility of CT can be conveyed to run perforation gun into highly deviated intervals.

C. Logging: Stiffness of Coiled can used as benefit to convey logging tools over long Distances Continuous logging in each direction.

D. Fracturing: Fracturing operations can be performed through Coiled Tubing or down the annulus of the production casing and the Coiled Tubing. It can be used to set plugs and Jet Cut perforations for multiple stage fracturing operations.

E. Fluid placement: Accurately place acid, cement and other chemicals at any point in the well bore.

F. Well Cleanout Clean out sand, scale and wellbore debris in and around from perforation in producing zones

150 FIGURE 3: COILED TUBING APPLICATION ( FRAC JOB )

Advantages of coiled tubing: Coiled tubing drilling presents several advantages over conventional drilling Operations:  Smaller footprint  Safer drilling operations while drilling underbalanced, especially with  Multiphase fluids (foam and nitrified fluids)  Continuous circulation  faster tripping operations (continuous pipe, no connections required)  ability to monitor and subsequently control down hole pressures more  efficiently  real-time down hole measurements of surveys, logging data (GR, CCL), and  pressure data at high-data rates using integral wire line inside the coiled tubing  superior directional control due to steering at BHA (reduced reactive torque effects)  improved pipe reliability for slim hole operations

Disadvantages of coiled tubing       

No pipe rotation possible. Fatigue (from bending at surface). WOB limitations / Buckling onset is earlier. Strength limitations. Diameter size limited. Heavy system. Hydraulics limitations.

151

Coiled Tubing Equipment Coiled tubing equipment can be divide into: 1. Surface equipment 2. Downhole equipment

1. Surface equipment

FIGURE 4: SMALL ENVIRONMENTAL F OOTPRINT

It consists of:

152

1. 2. 3. 4.

coiled tubing & coiled tubing reel injector head power pack control cap

1.1 Coiled tubing and coiled tubing reel Basic functions of the reel or equipment normally mounted on the reel include:     

Storing and protecting the CT string (drum) Maintaining proper tension between reel and injector head (reel drive system) Efficiently spooling the CT string on to the reel drum (level wind system) Circulating fluids with the drum rotating (swivel) Back-up depth measurement (reel mounted counter)

FIGURE 5: E FFICIENT R IG M OBILIZATION

1.2 Injector head and guide arch Basic functions of the injector head or equipment normally mounted on the injector head include:       

Injecting and retrieving the CT string Holding the CT string static Guiding the CT to the reel (gooseneck) Tension/compression measurement Depth/speed measurement (depth system sensor) Mounting place for primary pressure barrier (stripper) To provide the trust required to snub the tubing into the well against pressure or to overcome wellbore friction

153

2.

Bottom hole equipment:

Bottom hole assemblies for coiled tubing drilling application include; 1Motor assembly for non steered drilling applications. 2Directional drilling assembly for directional drilling. 3Bottom hole assembly for window-milling operation. 4Bottom hole assemblies, such as those used for running liners, whip stocks, scrapers, fishing, etc.

2.1.

Motor assembly for non steered drilling applications:

The Motor Head Assembly (MHA) is basically the combination of a coiled tubing connector, check valve and a disconnect which is incorporated into a single tool to minimize the tool length the tools are arranged in the following order to provide maximum safety and functionality:

• CT Connection (Top). • Check Value. • Disconnect (Bottom). • Circulation Sub. • Burst Disc (optional).

2.2.

Bottom hole Assembly for Directional Drilling

From the bottom up, a typical directional-drilling bottom hole assembly could include the following: • • •

bit drilling motor with bent housing FLOAT SUB ( CHECK VALVES )

•

UBHO (universal bent housing orienting) sub (if required) release tool (optional) orienting tool Down hole instrumentation (e.g., Down hole pressures, GR, CCL) Coiled tubing connector.

• • • •

154

2.3.

Bottom hole assembly for window-milling operation:

Window milling refers to cutting casing to begin directional drilling. This can be done conventionally or through tubing. In most cases it is done with a  whip stock.  Cement plug.  Whip stock/cement plug combination.

2.4.

Special Purpose Bottom hole Assemblies:

1- drilling and fishing jars: (Give extra pull by means of a hammer-type action when stuck or fishing) 2- accelerators: (Accelerate or increase the force of jarring effect in either direction while absorbing the shock to the BHA or coiled tubing) 3- underreamers: (Have expandable cutting arms to create a hole with a wider diameter than the inside diameter of the tubing or casing string that must be passed through) 4- float subs: (Which are check valves in the BHA) 5- overshots or spears: (Which are used for fishing) Drilling

Coiled Tubing

Sand control

Cementing

Applications Application of CT

WORK OVER

stimulation

155 Completion

Logging

Coiled tubing drilling Underbalanced drilling Is drilling with a bottom hole pressure below that of the pore pressure of the rock surrounding the wellbore. Reservoir fluids are allowed to enter the wellbore and are separated at the surface from the drilling fluid.

The underbalanced technique is used to:        

prevent formation damage caused by entry of damaging drilling fluids to the formation minimize many drilling-related challenges, such as loss of circulation and differential sticking increase rates of penetration minimize completion costs increase hole-cleaning efficiency (due to reservoir inflow) reduce mud costs improve economics by providing early reservoir production.

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 (3¾“ – 6¼“). • Logistical limitations relative to the coil (especially critical offshore).

Comparison between coiled tubing & jointed pipe

156

Generally, coiled tubing has several advantages and disadvantages over jointed pipe systems. For jointed pipe systems, drill string properties and tripping under pressure will need to be considered. The installation of a rotating head or snubbing system on a platform or rig with a fixed distance between rotary table and wellhead may cause severe challenges in rig up. Several previous operations on land rigs had to be redesigned to accommodate rotating control devices and rig assist snubbing systems.

T ABLE 1: GENERAL COMPARISON B ETWEEN CT & JP

Coiled tubing No connections made during drilling

Jointed pipe Connections require gas injection shut down causing pressure peaks

Higher pressure containment

Pressure of Rotating Diverters limited to 5000 psi static pressure.

Stiff wire line makes MWD systems simpler in

MWD systems unreliable in gasified

gasified fluids

systems

No snubbing system required

Pressure deployment requires snubbing unit

Maximum hole size 6”

No hole size limit

Hole cleaning more critical

Hole cleaning can be assisted by rotation

Potential for pipe collapse in high pressure

Special drill string connections required for

wells

gas fields

Through tubing drilling work possible

Through tubing work requires special rig floor tools on conventional rigs

BOP stack smaller

BOP stack up requires rotating diverter system.

Lower costs

Higher costs as a result of rig.

Limited with drag for outreach

Ability to drill long horizontal sections

157

TABLE 2: TIMING BETWEEN CT AND JOINTED PIPE

Rig/D.P. Action

158

M/U BHA Trip in Displace to Mud Drill Shoe Drill 200m Short trip (200m) Circulate POOH Snub out Change out BHA Snub in Trip in Circulate Trip in OH (200m) Drill 200m Short trip (400m) Circulate POOH Snub out Change out BHA Snub in Trip in Circulate Trip in OH (400m) Drill 200m Short trip (600m) Circulate POOH Snub out Change out BHA Snub in Trip in Circulate Trip in OH (600m) Drill 200m Short trip (800m) Circulate POOH Snub out

CTD Time (hours) 0 6 7 3 1 22 2 4 8 12 4 12 8 1 2 22 4 4 8 12 4 12 8 1 4 22 6 4 8 12 4 12 8 1 6 22 8 4 8 12

Action R/U & test CTD Equipment M/U BHA Trip in Displace to Mud Drill Shoe Drill 100m Perform wiper trip ea 25m Short trip Circulate POOH Deploy tool out of hole Change out BHA & cut CT Deploy toolstring in hole Trip in to shoe Trip in through OH (100m) Drill 100m Perform wiper trip ea 25m Short trip (200m) Circulate POOH Deploy tool out of hole Change out BHA & cut CT Deploy toolstring in hole Trip in to shoe Trip in through OH (200m) Drill 100m Perform wiper trip ea 25m Short trip (300m) Circulate POOH Deploy tool out of hole Change out BHA & cut CT Deploy toolstring in hole Trip in to shoe Trip in through OH (300m) Drill 100m Perform wiper trip ea 25m Short trip (400m) Circulate POOH

Time (hours) 60 6 5 3 3 15 4 0.8 3 5 2 6 2 5 0.8 15 4 1.5 3 5 2 6 2 5 1.5 15 4 2.3 3 5 2 6 2 5 2.3 15 4 3 3 5

Change out BHA Snub in Trip in Circulate Trip in OH (800m) Drill 200m Short trip (1000m) Circulate POOH Snub out L/D BHA

Total Time (hours) (days)

4 12 8 1 8 22 10 4 8 12 4

401 16.7

Deploy tool out of hole Change out BHA & cut CT Deploy toolstring in hole Trip in to shoe Trip in through OH (400m) Drill 100m Perform wiper trip ea 25m Short trip (5000m) Circulate POOH Deploy tool out of hole L/D BHA R/D CTD Equipment Total Time (hours) (days) Total Time w/o R/U inc. (hrs) Total Time w/o R/U inc. (days)

2 6 2 5 3 15 4 3.8 3 5 2 3 48 344.0 14.3 236.0 9.8

159

TABLE 3:C OST COMPARISON BETWENN UB-CTD OPERATIONS AND UBD JOINTED PIPE OPERATIONS Item Mobilisation

Days/U nit 1

Sum

Rig

Days/Unit

Sum

0

0

0

5

1,000,0 00 200,000

0

0

0

20,000

17

340,000

Rig Up

1,000,0 00 40,000

Daily Rate

40,000

10

400,000

Standby Rate

20,000

0

0

0

0

0

Top Drive

0

0

0

1,500

17

25,500

BHA

0

0

0

12,500

17

212,500

Mud Equipment

4,000

15

60,000

0

17

0

Mud

40,000

1

40,000

100,000

1

100,000

0

0

0

15,000

17

255,000

140,000

1

140,000

1,000,000

1

1,000,000

0

0

0

2,000

17

34,000

10,000

15

150,000

10,000

17

170,000

BOP

0

0

0

1,500

17

25,500

RCH/RBOP

0

0

0

17

0

Snubbing/PPM

0

0

0

0 (inc. in cost) 2,500

17

42,500

40,000

2

80,000

0

0

0

Separation Equipment Drill Pipe/Coiled Tubing DAQ Nitrogen Generation

Rig Down

160

CTU

Total Cost for one well

2,070,0 00

Total Cost for one well

2,205,000

Cost for two wells

3,140,0 00

Cost for two wells

3,410,000

TABLE 4: COMPARISON BETWEEN CTU, Coiled Tubing Drilling Unit

Unit Cost

Availability

Well Control Equipment Size Pressure Stripper

Drill String Size Comments

Reel

HYBRID CTU AND JP RIG

Hybrid CTD Unit

Conventional Rig

15-20k USD/day

40k USD/day depending on inclusion of separation package

20k USD/day

Available Possible standby charges

Not in Country Possible standby charges incurred

EDC41 No standby between wells

4-1/16" Stack

6-3/8" or 7-1/16" Stack

13-3/8" Stack. 11" stack possible to reduce height

5kpsi Integral

5kpsi Integral. For high pressure gas wells tandem strippers are used. Upper one as primary, lower stripper as back-up in case top leaks.

5kpsi Need RCH/RBOP which are available up to 5kpsi WP

Up to 2-7/8". Limited length

Up to 3-1/2". Larger reel.

E-line & hydraulic line reliability issues. Size of reel needed for 5000m of 23/8" coil needs to be large. If 2-5/8" coil or larger is required, the size and weight of the reel and transporter will be prohibitive. Installation costs and logistics to be accounted. Additional reels required on location for each operation (work & drilling). Will need to be specially designed/constructed for the project. Dependant on costs/time for spooling operations, a second dedicated unit would be required for the second drilling reel.

E-line & hydraulic line reliability issues. Size of reel needed for 5000m of 2-3/8" coil needs to be large. If 2-5/8" coil or larger is required, the size and weight of the reel and transporter will be prohibitive. Installation costs and logistics to be accounted. Additional reels required on location for each operation (work & drilling). Will need to be specially designed/constructed for the project. Dependant on costs/time for spooling operations, a second dedicated unit would be required for the second drilling reel.

Up to 4" DP dependant on connection type/size Connections should be gas tight. Gas wells have been drilled with IF connections without incident. Identification grooves need to be filled in.

NA

161

Pipe Life

Tripping pipe

162

Limited to certain number of cycles into & out of well. High pressures resulting from depths >4500m will result in very low life (less than one job). Not possible

Limited to certain number of cycles into & out of well. High pressures resulting from depths >4500m will result in very low life (less than one job). Singles possible with some units, though limited lift capacity

Needs to be monitored. Corrosion to be monitored and controlled.

20". Trip in triples.

Conventional

Max Pipe Size

Not possible to run jointed pipe.

Snubbing Unit

Max of 40-60klbs in hole. Maximum 60-100klbs out of hole depending on the injector head size.

7" possibly depending on the unit. Generally run in singles. Max. 60-100klbs in hole. Maximum 80-200klbs out of hole depending on injector head provided.

Training

Training possibly required, though crew should be experienced in UBD operations. Associated crew members and 3rd Party members to be trained. As part of package

All rig crew need training for UBD opeations

Insurance

Training possibly required, though crew should be experienced in UBD operations. Associated crew members and 3rd Party members to be trained. As part of package

Top Drive

NA

NA

Deployment Valve

Not required

Not required unless long BHAs are deployed

Needs to be installed. One year contrqact at $1500/day. Training requried by crew prior to use on UBD well Simplifies tripping procedures. Reliability to be determined prior to use. Well design needs to incorporate this.

Tie-back string

Needs 5" or 5-1/2" tie-back to surface. Complications due to internal profiles allowable. Retrievable at end of the operation or install final completion prior to commencing UBD operations.

7" tie-back string possibly required, though this has impact on the torque and drag imposed on the drillstring. Completion run after drilling operations complete

Interfaces

Possibly fewer interfaces if the package is supplied with separation capability.

Needs 5" or 5-1/2" tieback to surface. Complications due to internal profiles allowable. Retrievable at end of the operation or install final completion prior to commencing UBD operations. Possibly fewer interfaces if the package is supplied with separation capability.

HSE Case

CTU designed for live well interventions - HSE case simpler for UBD

CTU designed for live well interventions - HSE case simpler for UBD

More complex HSE case

Push-Pull machine limited to 60klbs in-hole. Snubbing unit required if forces exceed this.

Still waiting from EDC since Oct 2001

Various interfaces depending on the UBD contractor used.

Mobilisation

Expensive to mobilise CTD units: $1-2mm

Expensive. +/- $2mm

Rig equipment available. Some UBD equipment in country. Some would need to be sourced externally.

Can be less than 24hrs.

Can be less than 24hrs.

Can be in excess of 48hrs

Tripping quicker than jointed pipe. More time required for wiper trips.

Tripping quicker than jointed pipe. More time required for wiper trips.

Completion Running

Required prior to unit on location. CTU not possible to run completion.

Fishing Operations

Possible to fish both OB and UB. Less pull available and no rotational ability)

Hole Size Length of Section WOB Risk of HC Release

Up to 4-3/4" Maximum 300m 2-5klbs Low but severe consequenses for well.

Possible depending on the unit and the weight cpabilities. Generally 5" completion string too heavy for hybrid unit to handle. Possible to fish both OB and UB. Less pull available and no rotational ability) Up to 6-1/8" Maximum 600m (3-3/4" OH) 3-8klbs Low but severe consequenses for well.

Trips are generally slower than for CTD. Stalls less frequent and less requirement for wiping back to ensure cuttings removal. Possible after drilling section.

Corrosion Inhibitor Fluids System

Required if generated nitrogen is used. Smaller system required due to smaller overall system volume when using 5" tie-back. Ideally kill mud weight should be available on location during the operation in case of problems with the coiled tubing. May not be available in country.

Required if generated nitrogen is used. Smaller system required due to smaller overall system volume when using 5" tie-back. Ideally kill mud weight should be available on location during the operation in case of problems with the coiled tubing. Part of hybrid CTD unit.

Operations Round Trip Speed On Bottom Time

Conventional fishing possible

6-1/8" (through 7" liner) 1000m plus (6" OH) 10-20klbs Higher, but with sufficient control and mitigation measures this can be reduced. Sufficient back up measures can be introduced to the system and training implemented. Required if generated nitrogen is used. Large system available on the rig as part of the package. Requires kill mud weight system on location.

163

Separation

Pumps Availability

Rate

Pressure Nitrogen Equipment

Data Acquisition

Environmental

Sidetrack Options

164

System to be determined. Weatherford/Northlands package available for the operation if required. Standalone testing package can be used. Cost estimate at between $1025kUSD/day depending on package specifications and nitrogen requirements.

May be part of package. Smaller capacity will result in the well being drilled to the system limitations not to the ideal parameters determined by the well. Some units are restricted to 4mmscf/day which will limit the drilling parameters. Higher rates will require different separation equipment. Cost estimate $10kUSD. If nitrogen pumping is required for the operation, estimate per day with additional separation capacity at $25kUSD/day.

System to be determined. Weatherford/Northlands package available for the operation if required. Units rated for 60-80mmscf/day. Cost estimated at $25kUSD/day. This includes nitrogen generation/pumping capability.

Stimulation pumps generally used. Reliability less than conventional mud pumps for extended drilling operations. Generally low rate. Can be specified for rates expected during operation

Pump type to be confirmed. Either rig pump or stimulation type.

Available as part of rig package

Generally low rate. Can be specified for rates expected during operation Generally 6-8kpsi

Liner size to be determiend by DP size and rates/pressures required. Generally less than 4000psi Cryogenic or generated can be used. Generated nitrogen requires corrosion additives Conventional separation data acquisition systems available to integrate rig, mud, separation and nitrogen injection.

Can be up to 10kpsi if required Cryogenic or generated can be used. Generated nitrogen requires corrosion additives System needs to be adapted for use with all components: CT, mud, separation and nitrogen. Interface between CT and separation/mud can be complex. Complex hydraulic circuits involved. Pad size required generally less than half that of conventional drilling unit Openhole or cased hole. Slow, complex tools. Not as reliable as conventional sidetrack.

Cryogenic or generated can be used. Generated nitrogen requires corrosion additives System part of package unless separation package is not part of unit.

Complex hydraulic circuits involved. Pad size required generally half that of conventional drilling unit Openhole or cased hole. Slow, complex tools. Not as reliable as conventional sidetrack.

Conventional drilling operation. Needs to be controlled.

Conventional.

Stuck Pipe

Restricted to slide drilling. Chances increased of sticking due to insufficient hole cleaning and mechanically sticking. No tool joints removes OD changes.

Restricted to slide drilling. Chances increased of sticking due to insufficient hole cleaning and mechanically sticking. No tool joints removes OD changes.

Conventional. Rotation capability reduces chances. Better hole cleaning.

Freeing Stuck Pipe

Low tesile capacity. Low circulating rates. Reduced chance of freeing stuck pipe. No rotational capability. Weak point at top and/or bottom of BHA. If tubing stuck, need chemical cutter.

High pull capbility. High circulating rates possible. Rotating capability. Possibility to back-off and fish pipe.

Gas Injection

No connections. Pumping can be maintained throughout tripping pipe.

Low tesile capacity. Low circulating rates. Reduced chance of freeing stuck pipe. No rotational capability. Weak point at top and/or bottom of BHA. If tubing stuck, need chemical cutter. No connections. Pumping can be maintained throughout tripping pipe.

MWD/Drilling Assembly

Electric and hydraulic options. For UBD operations mud pulse tools are not recommended due to pressure cycling/surging.

Electric and hydraulic options. For UBD operations mud pulse tools are not recommended due to pressure cycling/surging.

Connections to be made. Drillstring needs to be bled off to floats each time. Time consuming. BHP varies each time. Surface pressure varies and slugs occur if using two-phase fluid. Conventional tools can be used if single phase fluid is utilised. EM-MWD tools required for two-phase fluids. These can be time consuming to trip.

Motor Selection

ADM motors - 2-3/8" to 31/8"

ADM motors - 2-3/8" to 31/8"

ADM to 4-3/4" (depending on hole size) or turbines

Finally: Coiled tubing drilling represents what many feel is the future in UBD due to our ability to maintain a relatively continuously underbalanced condition and MWD using a less problematic internal wire line approach. Current CT technology is limited with respect to depth and horizontal outreach capability for extended reach well applications. Pressure pulses during connections with a conventional jointed pipe can be minimized by using double pipe stands, rapid connections and appropriate circulation practices prior to breaking for connections to minimize the degree of degradation of under balance pressure that occurs during or after the connection is made. Top drive rigs offer the advantage of drilling with triple pipe stands which further reduces the number of connections required. Coiled tubing drilling allows the well to be maintained in an underbalanced state throughout the drilling and completion operations, virtually eliminating any wellbore damage and possibly reducing the need for well stimulation afterwards. In obayed D-2 the descision was to use jointed pipe conventional drilling but the precaution was taken to consider CTD operation in obayed D-4 at the same field

165

References Adams, N.J., Mack, S.K., Fannin, V.R., and Rocchi, Thierry, 1996: “Coiled-Tubing Applications for Blowout-Control Operations,” Journal of Petroleum Technology, May.

Allbee, James D., 1999: “Coiled Tubing Hang-offs: A Simple, Yet Effective Tool for the Future,” SPE 52121, presented at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, March 28-31.

Atherton, G.M. and Davis, M., 1996: “Coiled Tubing Drilling of Horizontal Re-Entry Wells, UK Land,” SPE 35546, presented at SPE (location unknown).

Beckman, Jeremy, 1997: “Coiled Tubing, Reamer Shoes Push Through Barriers in North Sea Wells,” Offshore, February.

166

166

Directional Drilling

This chapter introduces the fundamentals of directional drilling in underbalanced drilling operation. Directional drilling is a means of reaching otherwise inaccessible targets not only offshore, but on land as well. Reservoirs often underlie mountainous terrain, urban developments or other surface obstacles where building a rig location would be impractical. It’s the science and art of deviating a wellbore along a planned course from a starting (surface) location to a target (subsurface) location, both defined with a given coordinate system, in such a way that the hole can then be used for its intended purpose


IN UNDERBALANCED DRILLING

Contents

1-Directional Drilling (D.D) 2- APPLICATIONS

3-DIRECTIONAL DRILLING TOOLS AND TECHNIQUE 4- Geo-Pilot 5- Turbodrill

6- SURVEY TOOLS 7- HORIZONTAL WELLS

D

167

Directional Drilling (D.D) t’s the science and art of deviating a wellbore along a planned course from a starting (surface) location to a target (subsurface) location, both defined with a given coordinate system, in such a way that the hole can then be used for its intended purpose In another word the science of deviating a wellbore along a planned course to subsurface target whose location is at a given lateral distance and direction from the vertical, at a specified vertical depth. Drilling a wellbore with planned deviation from vertical to pre-determined target(s)


Directional Wells: 

Slant



Build and Hold



S-Curve



Extended Reach



Horizontal

Reasons for D.D 1-Sidetracking Side-tracking was the original directional drilling technique. Initially, sidetracks were “blind". The objective was simply to get past a fish. Oriented sidetracks are most common. They are performed when, for example

168 FIGURE 1SIDETRACKING

2-Inaccessible Locations:

FIGURE 2 INACCESSIBLE L OCATIONS :

3-Fault Drilling If a well is drilled across a fault the casing can be damaged by fault slippage. The Potential for damaging the casing can be minimized by drilling parallel to a fault and Then changing the direction of the well to cross the fault into the target.

FIGURE 3 FAULT DRILLING


Targets located beneath a city, a river or in environmentally sensitive areas make it necessary to locate the drilling rig some distance away

169

4-Multi-well Platform Drilling


Multi-well Platform drilling is widely employed in the North Sea. The development of these fields is only economically feasible if it is possible to drill a large number of wells (up to 40 or 60) from one location (platform). The deviated wells are designed to intercept a reservoir over a wide a real extent. Many oilfields (both onshore and offshore) would not be economically feasible if not for this technique.

5-Salt Dome Drilling:

FIGURE 4M ULTI -WELL P LATFORM DRILLING

Salt domes have been found to be natural traps of oil accumulating in strata beneath the overhanging hard cap. There are severe drilling problems associated with drilling a well through salt formations. These can be somewhat alleviated by using a salt-saturated mud. Another solution is to drill a directional well to reach the reservoir .

170 FIGURE 5SALT D OME DRILLING

6-Relief Well:

FIGURE 6R ELIEF W ELL:

7-Horizontal Wells: Reduced production in a field may be due to many factors, including gas and water coning or formations with good but vertical permeability. Engineers can then plan and drill a horizontal drain hole. It is a special type of directional well Horizontal wells are divided into long, medium and short-radius designs, based on the buildup rates used. Other applications of directional drilling are in developing geothermal fields and in mining.


The objective of a directional relief well is to intercept the bore hole of a well which is blowing and allow it to be “killed". The bore hole causing the problem is the size of the target. To locate and intercept the blowing well at a certain depth, a carefully planned directional well must be drilled with great precision

171

FIGURE 7H ORIZONTAL WELLS

Advantages of horizontal drilling 

increasing formation exposure



improving well deliverability



eliminating water and gas coning



reducing overall development costs

APPLICATIONS


The most common applications of directional drilling        

Offshore Multi-well Drilling Relief Wells Inaccessible Locations Fault Controlling Salt Dome Drilling Sidetracking Horizontal Wells Controlling Vertical Wells Horizontal Wells

Offshore development is the most common application of directional drilling. In fact, controlled directional methods got their start in the coastal areas of California. With the costs and logistics involved in setting up an offshore platform, the ability to drill multiple wells from a single surface location is essential to any development project's success. As horizontal and extended-reach drilling capabilities increase, the time may come when an operator will be able to develop an entire offshore field from one surface location. Directional drilling is a means of reaching otherwise inaccessible targets not only offshore, but on land as well. Reservoirs often underlie mountainous terrain, urban developments or other surface obstacles where building a rig location would be impractical.

172

Directional drilling is also a valuable well control tool. When a blowout occurs and surface control methods are impractical, an alternative is to drill a relief well and pump kill fluids directly or indirectly into the blowout well's annulus.

1. DEVIATION IN VERTICAL WELLS CAUSES OF WELLBORE DEVIATION Rotary drilling involves the use of an elastic drill string, which tends to buckle under axial forces, and which tends not to withstand lateral forces. Therefore, the drill string has long been recognized as a key to controlling wellbore deviation. The role of the drill bit has not been as obvious, although it's been known for a long time that there exist forces at the bit that can affect its path, and that these forces vary among different bit types even in the same formation, indicating that bit design and geometry relate to wellbore deviation. The exact causes of wellbore deviation are unknown. We can say, however, that the following are all contributing factors:


 Formation  Type, lithology  anisotropy  dip  Bottomhole assembly size, configuration  stabilizer types, size, positioning  drill collars  reamers and other tools  Drilling parameters  Weight on bit  Hydraulics  Hole angle  Annular clearance  Bit type, design features

FIGURE 8:FORMATION TYPE AND LITHOLOGY

173 FIGURE 9:FORMATION ANTICLINE

Wellbore deviation results from forces acting at the bit. We can separate a study of these forces into two parts:  Bit/rock interaction -- the study of bit behavior in various rocks under the action of applied bit loads  Drill string mechanics -- the analysis of drill string behavior under the action of imposed forces

1.1 Bit/rock interaction We can break down the mechanical actions of drilling a rock into three categories (Parameters affecting hole deviation that are due to rock/bit interaction):


 Percussive action  Drag-rotary action  Combined percussive/drag-rotary action

FIGURE 10:B IT/ROCK INTERACTION

Rolling cutter bits fall into the combined percussive/drag-rotary classification, while, fixed cutter PDC and diamond matrix bits fall into the drag-rotary action category.

174

1.2 Drill string mechanics The deviating forces that the drill string imparts to the bit relate directly to the string's Configuration, the hole geometry, and the weight on the bit.Structurally speaking, a drill string is a flexible, elastic member, unable to resist lateral loads and subject to buckling under axial loads.


The shape of this buckling depends on how much weight is applied at the bit (a) and drill sting bucking effect on hole deviation (b). Once buckling occurs, the bit is no longer vertical, and hole deviation results.

FIGURE 11:DRILL STRING MECHANICS

The extent to which buckling occurs depends on the drill string's rigidity and length. Techniques that have been used to minimize buckling include  Reducing weight-on-bit to a value less than that of the critical weight which induces first order buckling  Adding stabilizers to the drill string at points of maximum deflection in the predicted buckling mode  Using large-diameter drill collars

175

From the standpoint of reducing buckling, the ideal bottom hole assembly (BHA) would have a diameter equal to the hole diameter. Of course, this is a practical impossibility, so we instead use stabilizers, which have larger diameters than drill collars, to limit the BHA's lateral movement.


FIGURE 13: S TABLIZING TOOL

FIGURE 12: TYPES OF STABLIZING TOOLS

176

Types of Directional Wells

2- Build, Hold and Drop -- after a relatively shallow deflection, this pattern holds angle until the well has reached most of its required horizontal displacement. This pattern is most applicable to wells exposing multiple pay zones, or wells subject to target or lease boundary restrictions.


1-Build and Hold -- this pattern employs a shallow initial deflection and a straightangle approach to the target. It's used to reach single targets at moderate depths, and sometimes for drilling deeper wells with large horizontal departures.

177


3- Continuous Build -- unlike the Type 1 and 2 patterns, this trajectory has a relatively deep initial deflection, after which angle is maintained to the target. The continuous build pattern is well-suited to salt-dome drilling, fault drilling, and sidetrack sand redrills.

178

4- Build, Hold and Build -- this is the general pattern describing horizontal wells. The decision to drill horizontally is primarily based on reservoir engineering and reservoir management considerations.

179


DEVIATION CONTROL METHODS Along with minimizing well costs and maintaining a safe operation, a primary objective of drilling is to obtain a usable hole. A key to meeting this objective is to reach the target zone with minimal abrupt changes in hole angle, so as to allow for setting casing and successfully producing the well. There are three basic techniques for controlling wellbore deviation:


 We may use a pendulum assembly, consisting of the bit, drill collars and strategically positioned stabilizers, to decrease hole angle (i.e., straighten the hole).  We may use packed hole assemblies, consisting of reamers, short collars and Stabilizers, or square drill collars, to "lock in" the bit and maintain a constant hole angle.  We may use directional drilling tools (e.g., downhole motors with bent housings). The use of directional drilling tools more properly falls under the category of controlled directional drilling. We mention it here, however, to emphasize its use as a "straight hole" drilling method, and to point out that it is the most effective of these three techniques for controlling hole angle and direction. In fact, in many drilling applications, it has superseded the other techniques. Still, there are situations that call for the exclusive use of pendulum or packed hole assemblies to control deviation (e.g., at some land locations where drilling characteristics are well known, it may not be economical to use directional drilling tools for deviation control).

2.1 bottomhole assembly 123-

180

Pendulum assembly (dropping angle) Fulcrum assembly (buildup angle) Packed hole (hold angle)

2.

DIRECTIONAL DRILLING TOOLS AND TECHNIQUES

2.1 DOWNHOLE MUD MOTORS

The distinguishing feature of downhole motors is that they are designed to turn the bit without rotating the drill string. Thus, it's possible to orient the bit in a desired direction, and maintain it in this direction throughout the bit run. Moreover, drilling in this "oriented" mode reduces the rig's power requirements and reduces wear on both surface equipment and tubular. Downhole motors come in two basic types:  

positive displacement motors (PDM) Turbine motors.

The positive displacement motor is easily the most versatile tool for building or maintaining hole angle, or for minimizing crooked hole tendencies. It can be run with a bent sub or eccentric stabilizer to initiate deflection. Or, in "crooked hole "formations, it can be run without these accessories to serve as a deviation control tool.

For maximum directional control with a minimum of trip time, we may use a motor with a bent housing. The heart of the positive displacement motor is the rotor-stator, consisting of a helicoidally rotor that moves within a molded, elastomer-lined stator.


Downhole motors (commonly known as mud motors because they are hydraulically driven by the circulating drilling fluid as it moves down the drill string) have played an integral role in the advancement of directional drilling technology, and in "straight hole" drilling as well. The flexibility and control that they provide is far beyond that attainable with other wellbore deflection techniques, and their use has become prevalent in an ever-widening range of applications, including slim hole and coiled tubing operations.

181


FIGURE 14 DOWNHOLE MUD MOTORS

When circulating fluid is forced through this assembly, it imparts torque to the rotor, causing it to turn eccentrically. A universal connection transfers this rotation through a bearing and drive-shaft assembly to a rotating bit sub, which turns the bit. Positive displacement motors provide excellent steerability for deflecting or straightening the well course. In addition, they allow us to increase the bit RPM without increasing the drill string rotation, and to drill with less weight-on-bit. This can result in higher penetration rates compared to drilling with a rotating Kelly, and reduced drill pipe and casing wear--an important consideration, especially when drilling high-angle holes. Positive displacement motors are available in a wide variety of sizes, rotating speeds, rotor/stator configurations and output characteristics, for a broad range of downhole conditions. Turbine motors operate at relatively high rotary speeds, and so are run exclusively with fixed cutter (PDC or natural diamond) bits. Some operators see this as an advantage in certain situations, in that these characteristics may help eliminate "bit walk" to the right, allow for higher bit weight (and thus improved drilling rates) and a smoother hole for logging and casing operations than a PDM would provide Turbine motors have narrower operating ranges than positive displacement motors. The relatively small diameter of the turbines and resulting higher rotational speeds translate into greater fluid flow requirements. They also tend to be longer than PDMs, which limits their ability to make high angle directional changes. Because of these limitations, which are inherent in the turbine motor design, positive displacement motors are used much more commonly.

182

The operator and directional service company representative should consider the following basic information when selecting a downhole motor :

Depths (kickoff point, target, etc.) Hole size Formation hardness faulting build rate Bottomhole temperature Conditions at the kickoff hydraulics program mud program rig pump capabilities

2.3 DEFLECTION TOOLS Although the mud motor is overwhelmingly the tool of choice for controlled directional drilling, there are other tools that may be of some use in certain areas. These include


         

 directional wedges  jet bits with oriented nozzles  specialized Bottomhole assemblies

3.4.1 Whipestocks: The wedge is attached to the Bottomhole assembly by means of a shear pin. The assembly is lowered to bottom and oriented in the proper direction. The driller applies weight to set the wedge and shear the pin, drills ten to fifteen feet of under gauge hole, and then trips the tools so that a full-gauge hole opener can be run. After drilling the section, a survey is made to assure proper direction, and the process is repeated until the build section of the well is completed.

183


The directional wedge technique is time-consuming, has limited applications, and requires a high degree of technical expertise to properly implement. For these reasons, it is seldom used.

FIGURE 15W HIPESTOCKS

3.4.2 Jet bits with oriented nozzles The bit is lowered to bottom , the jet is oriented in the desired direction, and mud flow is initiated with no drill string rotation. After hydraulically gouging a small pilot hole (about 3 feet), the driller initiates conventional rotary drilling to open the section to full gauge. The process is then repeated. Hole surveys are made after drilling 10 to 15 feet of build section.

184

FIGURE 16J ET BITS WITH ORIENTED NOZZLES

3.4.3 Rotary Steerable System Have proven their value over conventional mud-motor steerable systems in three ways:

By cutting drilling time and expense; extending the reach of horizontal wells; and succeeding at temperatures and pressures where mud motors cannot operate. This article provides a brief overview of the technology, followed by three case histories that illustrate the value of these systems. RSS general layout

TECHNOLOGY OVERVIEW Weatherford’s Revolution rotary steerable system (RSS) uses point-thebit drilling technology and includes in the design both a non-rotating sleeve stabilizer and a rotating near-bit “pivot stabilizer” to orient the drill bit axis with the axis of the intended hole trajectory. A rotating drive shaft runs through the center of the non-rotating sleeve to transmit torque and weight through the tool to the drill bit. The bit is steered through the formation by deflecting the drive shaft within the nonrotating sleeve stabilizer,. The drive shaft is deflected in a direction opposite to the required trajectory, and the pivot stabilizer acts as a fulcrum to point the bit in the required direction. The hydraulic force for deflection is provided by a pump driven by relative rotation between the center shaft and the non-rotating outer sleeve. Both the non-rotating sleeve of the steering unit and the rotating pivot stabilizer are close to the gauge of the hole to maximize the directional performance of the RSS. The offset of the drive shaft – the degree of steering – is controlled by the onboard navigation and control electronics of the RSS. Tool face and deviation rates are programmed from the surface using drillstring rotation, while mud pulse LWD provides uplink telemetry. The entire system offers a very compact design to facilitate logistics and deployment.


FIGURE 18R OTARY S TEERABLE SYSTEM

185

Advantages of RSS wells: •

Greater bit efficiencies

•

Less shock and vibration

•

Reduced surface & down hole equipment attrition

•

Reduction in “stuck pipe” events.

•

Lower mud and cement volumes

•

Reduced back reaming and fewer tripping problems

•

Easier casing and completions installation

•

Greater efficiency of wireline and well servicing operations


System-Specific Requirements Once the decision is made on which particular rotary steerable system is capable of economically meeting the objectives of a given drilling program, the focus immediately shifts to the drill bit that will make reaching the goal possible. Security DBS offers a full range of flexibility in “push-the-bit,” as well as “point thebit” options, each specifically designed for your drilling program. “Push-the-bit” systems typically require a shorter gauge area than PDC bits used on motor applications. This reduction in lateral area affords greater directional responsiveness when a side force is applied by the steering unit. Bit designs can be tailored specifically for applications requiring: • Laterally aggressive bits with little or no passive gauge area in high steerability applications to yield the highest degree of dogleg severity • A combination of these features to reach a given set of designer well objectives By contrast, “point-the-bit” systems make the bit more “axially aggressive.” This feature allows the bit to penetrate at the same rate but with a lower weight on bit and it can be used to increase ROP. Typically, “point-the-bit” systems increase the gauge length for stability and use the internal shaft deflection for directional changes. •

186

 Rotary steerable assemblies have the potential to reduce overall dogleg severity


 Rotary steerable can improve hole cleaning

187


Geo-Pilot Basic Operating Principle By using a pair of cams mounted midway between two bearings, the center of the drive shaft is deflected off center, thus causing the bit to be deflected in the opposite direction. When the cams are oriented opposite each other, they cancel out and the assembly will drill straight ahead. [Notice in the picture that both cams are oriented in the same direction. Imagine the inner cam rotating 180 degrees. It now shoves the drive shaft back to the center. This concept points the bit rather than trying to shove it sideways. Because of this, we can take advantage of the benefits of long gauge bits - better hole follow through (the bit has more of a tendency to drill ahead on a centerline instead of spiraling around a centerline). The inherently more stable bit design reduces vibration, which is already greatly reduced due to the elimination of the mud motor. And by reducing hole spiraling, the resulting periodic troughs in the low side of the hole that can act as cuttings traps, are reduced or eliminated. And 100% rotation keeps the well as clean as practical and greatly reduces the need for short trips and back reaming. [note: baker Hughes will not allow customers to back ream with their tool Advantages of geo pilot Tools • Allows use of long gauge bits: • Long gauge bits promote reliability through smooth running • Initial GeoPilot reliability target 400 hours between services • 2002 GeoPilot reliability target 1400 hours between services

188 FIGURE 17G EO-PILOT B ASIC OPERATING PRINCIPLE

Geo-Pilot Rotary Steerable System


Geo-Pilot design Concept

189

3.4.4 Specialized Bottomhole assemblies


In developed fields, where drilling tendencies and formation characteristics are well known, it is often possible to build or drop hole angle with a reasonable degree of control by using drill collars, stabilizers, reamers and other BHA components, without having to resort to mud motors or other deflection tools.

FIGURE 18SPECIALIZED B OTTOMHOLE ASSEMBLIES

3.4.5. Turbodrill This is another type of mud motor which turns the bit without rotating the drillstring. Unlike a PDM a turbodrill can only be powered by a liquid drilling fluid. The Turbodrill motor consists of bladed rotors and stators mounted at right angles to fluid flow. The rotors are attached to the drive shaft, while the stators are attached to the outer case. Each rotor-stator pair is called a stage; a typical turbodrill may have 75-250 stages. The stators direct the flow of drilling fluid onto the rotor blades, forcing the drive shaft to rotate clockwise . Turbodrills can be used for directional drilling in much the same way as PDMs. Turbodrills are also used in straight-hole drilling as an alternative to rotary drilling. Such a technique has the following advantages:

190

 String and casing wear reduced  Lower torque applied to string  Higher RPM at bit (better penetration rates).


FIGURE 19TURBODRILL

191

3.5 SURVEY TOOLS 3.5.1 Magnetic Single Shot


The oldest and simplest type of directional survey tool is the mechanical drift indicator

This device works on a pendulum, or plum-bob principle. It gives no indication of azimuth, but measures only a well's inclination from vertical. It is used today for surface hole drilling, shallow vertical wells and other applications where dog-leg severity and horizontal departure are not likely to become significant problems.

192

Magnetic survey tools record the inclination, azimuth and tool-face orientation at various points, or stations, along the well course. Two basic types of tools are available: single-shot devices, which record one measurement (usually near the bottom of the well), and multi-shot devices, which can record a number of survey measurements in one running. Tools can be dropped or pumped to bottom, lowered on slick line or wireline, or run as part of a measurement-while drilling (MWD) package. When tools are dropped to bottom--typically before tripping

pipe--they can be recovered when the pipe is pulled, or else by means of an overshot. The basic components of a conventional magnetic survey tool  A magnetic compass and angle-indicating unit  A camera unit for recording measurements on a photographic  A timer or motion sensor, which activates the device at a desired time or depth interval

3.5.2. WIRELINE STEERING SYSTEMS

3.6 MWD AND LWD SYSTEMS One of the most important advances in modern petroleum technology has been the development of real-time Measurement-While-Drilling systems to transmit drilling and directional information, and Logging-While-Drilling systems to provide formation evaluation data. MWD and LWD systems have made it possible to monitor and control operations even as drilling is taking place, by allowing operators to:  Measure drill bit position and trajectory, Monitor penetration rate, actual weight-on-bit, downhole torque and drag, vibration and other drilling parameters,  Compute pore pressures and get an early warning of potential overpressure zones,  Detect and correlate geologic markers and formation tops,  Evaluate formations even as they're being drilled.


A wireline steering system consists of a Bottomhole assembly that accommodates a Measurement probe run on wireline. The probe employs magnetometers to measure direction, and accelerometers to measure hole angle. It also measures the orientation of the tool face, and other parameters such as time, depth and tool temperature.

Systems are modular in design, and can be run with various sensor combinations to fit the requirements of the well plan. MWD tools operate by creating pressure pulses in the mud column, in response to inputs from the various sensors. Depending on the type of tool, the pulses may be positive, negative or continuous. These pulses are converted into electronic signals, which are processed and displayed at the surface.

193

Logging-While-Drilling, or LWD tools, operate on basically the same principles as conventional wireline logging tools. The dual resistivity contains a gamma ray tool, and two sets of transmitters and receivers to provide shallow and deep resistivity readings. The compensated density-neutron tool measures density and neutron porosity in a manner similar to that of analogous wireline tools. When drilling with a mud motor, these particular tools are run above the motor assembly--in other words, about 30 or 40 feet above the bit. In some applications, such as drilling in very thin, dipping pay zones, even this small "information gap" between the bit and the tool could lead to problems. For this reason, systems have now come into use that allow "at-the-bit" measurements to be taken within a few feet of bottom.


Although LWD tools work in generally the same manner as conventional logging tools, tool responses will most likely be different in highly deviated wells from what they would be in vertical wells. These responses require special methods of interpretation.

FIGURE 20MWD

194

3.8 GEOLOGIC STEERING Until relatively recently, it was easy to make a distinction between planning a well trajectory and actually following it. We would develop a directional profile as part of the well plan, and then go out and drill the well along this pre-assigned course, taking periodic surveys and making corrections as necessary. This process is referred to as geometric steering.

At the same time, improved directional drilling technology has presented the industry with new challenges. As companies have begun drilling longer horizontal and extended-reach wells, it has become clear that even the most precise geometric steering capabilities may not be adequate once a well approaches the pay zone. Horizontal and high-angle directional wells often have as their objectives thin, heterogeneous, and sometimes steeply dipping reservoirs. In such formations, a preassigned trajectory may lead right out of a productive interval. Even if the difference is only a matter of a few feet, the result may be an unsuccessful well . Fortunately, integrated MWD and LWD capabilities have provided the option of geologically steering wells as they approach their respective pay zones----of using real-time formation measurements to stay within target intervals. In a growing number of instances, operators have been able to geologically steer wells away from zone boundaries or fluid contacts and execute successful well completions.


Geometric steering has served the industry well, and it remains an important aspect of directional drilling. With a bent-housing positive displacement motor, a welldesigned bottomhole assembly, and MWD capabilities, it's possible to minimize wellbore deviation and follow a planned course simply by changing the tool face orientation as needed.

195

4 HORIZONTAL WELLS 4.1 INTRODUCTION Horizontal drilling is the process of directing part of a well course through a reservoir such that its inclination angle is approximately 90° from vertical. This horizontal section may be anywhere from a few feet to thousands of feet in length.


Horizontal wells can trace their roots back to at least the 1930s (Ranney, 1939). But it is only since the 1980s that advances in directional drilling and formation evaluation have brought theminto the mainstream of oil and gas operations. Since then, in a number of fields, they have significantly outperformed conventional wells in terms of increased productivity, improved ultimate recovery and lower overall development costs. There have also been disappointments along the way, which have shown that the benefits of horizontal drilling are largely contingent on reservoir characteristics.

4.1.1 Horizontal Drilling Applications Horizontal wells work to best advantage in thin reservoirs having a relatively high ratio of vertical to horizontal permeability (vertically fractured formations are prime candidates) and a potential for drawdown-sensitive production problems like water and gas coning. Other common candidates for horizontal drilling are:    

Reservoirs that would otherwise be economically inaccessible Heavy oil reservoirs Channel sand and reef core reservoirs Hoal bed methane reservoirs

196 FIGURE 21 HORIZONTAL WELLS

4.2 WELL CONFIGURATIONS


Horizontal drilling begins with a more-or-less vertical surface section (except in the case of slant drilling rigs, where this section is pre-inclined), followed by a bend section, which progresses from approximately 0° to 90° inclination with depth, and finally by a horizontal or lateral section. The transfer of weight to the drill bit during the horizontal drilling phase involves different concepts, which translate into different well configurations. We may generally distinguish these configurations based on radius of curvature as follows:

FIGURE 22WELL CONFIGURATIONS

   

Long turn radius (LTR) Ledium turn radius (MTR) Lhort turn radius (STR) Ultra-short turn radius (USTR)

The considerations that enter into selecting one of these well configurations include     

cost well spacing and lease restrictions conditions of re-entry wells reservoir rock characteristics production methods  well objectives  problem-causing lithologies above the pay zone  amount of total horizontal departure  completion methods

197


Long Radius

Medium Radius

Short Radius

Build rate Build radius (ft) Hole size

Up to 6° per 100 ft 1000 - 3000 No limits

6 - 20° per 100 ft 300 - 700 4 3/4, 6 1/8, 8 1/2, 4 3/4, 6 1/2, 9 7/8

1.5 - 3° per one ft 20 - 40 4 3/4, 6 1/2

Drilling Method

Rotary or steerable motor systems for curve and horizontal sections

Specially designed motors for angle build section; rotary or steerable motor systems for horizontal sections .

Tubulars used

Conventional tubulars.

Heavy wall drill pipe for build rates of up to 15° per 100 ft; special service drill pipe for higher build rates. No limits

Specially designed deflection tools or articulated motors for angle build section; rotary tools and special drill pipe for horizontal sections. Special articulated tubulars; special drill pipe with short articulated motors. Rotary: No limits Motor: Diamond or PDC No limits Special

Drill bit

No limits

Drilling fluids Surveying

No limits No limits

Coring

Selective completion capabilities Multiple pay zones Artificial lift capabilities

Workover capabilities Typical productivity index increases in non-fractured zones Typical productivity index increases in fractured zones Production enhancement ratio (horizontal/vertical well)

Conventional coring, no limits

No limits MWD capabilities limited for hole sizes smaller than 6 1/8 inches Conventional coring, no limits

Yes

Yes

No

No

Yes

Yes

All types

All types

Yes 3.5

Yes 2.5

Rod pumps in vertical portion Yes 2.5

>10

>10

6

7

3-foot core barrel, 1-inch diameter core

Depends on fracture distribution Varies widely; can be from 1 to 100

TABLE 1 COMPARE THE BASIC CHARACTERISTICS OF LONG, MEDIUM AND SHORT RADIUS WELLS .

198

4.2.1 Long Turn Radius Drilling A long turn radius well is a well having at least one section with a build rate of between 1° and 6° per 100 ft, and a build radius of 1000 ft or more. Long radius applications include:

The advantages of long radius drilling over other horizontal drilling methods include minimal dogleg severity, attainment of horizontal departure while drilling the build section, and the ability to employ either conventional rotary bottomhole assemblies or steerable drilling systems. In addition, long radius methods impose no restrictions on hole diameter, bit type, coring or MWD capabilities, and they permit various options with respect to completion, stimulation and artificial lift.

4.2.2 Medium Turn Radius Drilling A medium turn radius well has at least one section with a build rate angle of between 6° and 20° per 100 ft in the rotary mode, and as much as 30° per 100 ft in an oriented mode, in reaching horizontal. The radius of curvature ranges from about three hundred up to a thousand feet. Medium-radius wells are appropriate for areas that could benefit from horizontal drilling, but where long-radius methods are either unnecessary or impractical, as would be the case when lease boundary restrictions limit the well course. They are particularly applicable for re-entry wells, reef reservoirs, fractured reservoirs and reservoirs with potential for gas or water coning.


 drilling multiple, extended-reach wells from offshore platforms or other single surface locations  reaching otherwise inaccessible locations  drilling exploratory wells over long intervals  drilling wells that require zone isolation and selective completion/stimulation

The primary advantage of medium radius over long radius drilling is that the well profile is shorter. A medium-radius well can reach the lateral section with greater precision at a shallower depth, with less departure from vertical, and in less time than it takes to drill the curved section of a long radius well. Torque and drag tendencies are also less than in long-radius wells. The vertical portion of the well can be drilled deeper and casing set deeper before beginning the directional drilling phase, and upon completion, production equipment can be set in the vertical section, closer to the pay interval.

199

4.2.3 Short Turn Radius Drilling


The build rate angle on a short radius well may range from 1 to 3 degrees per foot. The radius of curvature may be 50 feet or less, with a hole size of between 4 3/4 inches and 6 1/2 inches.

FIGURE 23SHORT TURN R ADIUS DRILLING

Short-radius applications include infill drilling in depleted reservoirs, drilling shaly intervals or other trouble-prone formations and drilling multiple drainholes from one vertical wellbore. They are also proving useful for enhanced oil recovery, particularly steam flooding. Short-radius wells are relatively inexpensive. They provide easy, precise entries to the horizontal sections, and can reach lateral displacement at a minimum measured depth. This makes them particularly appropriate, and sometimes necessary, for shallow reservoirs. Disadvantages of short radius wells include special drilling equipment requirements such as articulated tubulars, limits on hole size and reach, limited azimuth control, and an inability to run logging tools or casing. Coring abilities are limited to 3-foot sections of 1-inch diameter core, and diamond or PDC bits must be used when drilling with a short, articulated motor.

4.2.4 Ultra-Short Turn Radius Drilling

200

A special class of short-radius wells is the ultra-short radius well, which effectively has no bend section. Ultra-short drilling methods employ jetting techniques and coiled tubing to eliminate angle build sections, and are used in soft, unconsolidated formations to drill multiple drainholes from existing vertical wells.

Directional Drilling FIGURE 24R ADIUS DRILLING

201

References Geotechnical Engineers Handbook, Robert W. Day, McGraw-Hill, 2000

Horizontal Directional Drilling, Good Practices Guidelines, HDD Consortium, May 2001


J. D. Hair & Associates, Louis J. Capozzoli & Associates, and Stress Engineering Services (1995).“Installation of Pipelines by Horizontal Directional Drilling, An Engineering Design Guide,” prepared for the Offshore and Onshore Design Applications Supervisory Committee of the Pipeline Research Committee

202

“Horizontal Directional Drilling, Good Practices Guidelines,” HDD Consortium, May 2001.

202

Drilling Problems In Underbalanced Drilling

This

chapter introduces the main problems in conventional, deviated and underbalanced holes. Problems associated with the drilling of oil and gas wells are largely due to the disturbance of earth stresses around the borehole caused by creation of the hole itself and by drilling mud formation interaction. Earth stresses, together with formation pressure attempt to re-establish previous equilibrium by forcing strata to move toward the borehole.

Content 1. 2. 3. 4.

Lost Circulation Well Kicks Other Hole Problems Problems Encountered during Underbalanced Drilling 5. Problems Encountered during Drilling Obayed Field

203

Anticipated Problems An event which causes the drilling operation to stop is described as a NonProductive Time (NPT) event. Pipe sticking and lost circulation are the two main events which cause NPT in the drilling industry. Well kicks, of course, require operations to stop and when they occur can result in a large NPT. The average NPT in the drilling industry is 20%. Events such as: 1. 2. 3. 4.

Pipe Sticking lost circulation Well Kicks Other Problems

Pipe Sticking The sticking of drill pipe inside the borehole is one of the main Hole problems associated with drilling Operations. Mechanisms: 1. Differential Pipe Sticking 2. Mechanical Pipe Sticking

1. Differential Pipe Sticking

   

204

Drill String comes in contact with filter cake of a permeable zone subjected to a lower pressure. The pressure differential across the filter cake enables the drill string to be embedded. Drill string further differentially stuck if side load and over balance is higher on other side. Pipe is differentially stuck if it cannot be moved up, down or sideward.

Differential Sticking Force = (Mud Hydrostatic-Formation Pressure) x (effective area of contact) x (friction factor)

 Warning:  Prognosed low pressure sands  Long / unsterilized BHA.  Increasing overpull, slack off weight or torque to start string movement.

 First action:  Apply torque and jar down with maximum trip load.  Spot a pipe releasing pill if the string does not jar free.

 Preventing Action  Maintain minimum required mud weight.  Keeps string moving when BHA is opposite suspected zones.  Minimize seepage loss in low pressure zones.  Minimize unsterilized BHA & use spiral DC.  Control drill suspected zones

 Freeing Differential Pipe Sticking 1. Reduction of Hydrostatic Pressure 2. Spotting Pipe Release Agents 3. back off operation FIGURE 1: DIFFERENTIAL STICKING

1.1 Reduction of Hydrostatic Pressure Reducing the Hydrostatic pressure will enable the freeing of the pipe. The lowering of hydrostatic pressure reduces the side loading forces on the pipe and frees the pipe. Considerations:     

Are there pressurized zones in the open hole. Will exposed zones kick if hydrostatic pressure is reduced. Mechanical stability of formation Confidence level in pore pressure estimates Volumes of fluids required to carry out operations.

1.1 Spotting Pipe Release Agents It is blend of Surfactants, emulsifiers, diesel oil and water. It used to Penetrate filter cake and reduce surface tension between pipe and filter cake. A mixture of surfactant and diesel oil is the most widely used fluid thereby creating a thin layer between pipe and mud cake to decrease the value of friction coefficient and increasing the effectiveness of mechanical attempts to pull free.

205

For effective freeing of stuck pipe, a minimum volume of 150 bbl of organic fluid is suggested and should be left for a minimum of 8 hrs to work through the filter cake properly 1.2 Back-off operation Back-off operations involve the removal of the free portion of the drill string from the hole. Before a back-off operation can be attempt; the position of the stuck pipe should be determine as accurately as possible. The back of procedures start with running A back-off shot to be positioned against a drill pipe tool joint that is found to be free (back-off point). Then, a lift hand torque and slight positive tension above the back-off weight (pre-stuck hook load minus stuck pipe weight are applied. The back-off shot is detonated and The pipe should come free which will indicated by a sudden decrease in hook load. The pipe is rotated to lift and picked up to confirm back-off. Finally, POOH The drill string section lift in the hole is discribed as fish

2-Mechanical Sticking Pipe is completely stuck with little or no circulation unlike differential sticking where circulation takes place.

Causes  

Bridging or Hole Packing off Formation and BHA (Wellbore Geometry Understanding the problem is the key to solution!!

1. Hole Pack off (bridging)      

Shale Instability Unconsolidated formations Settled cuttings due to inadequate hole cleaning Junk in well Cement blocks Fractured or faulted formations

2. Formation & BHA

206

   

Key Seating Under gauge hole Ledges & Micro doglegs Mobile formations FIGURE 2: MECHANICAL STUCK

HOLE PACK OFF (BRIDGING) 1.1 Hole Pack Off-Settled Cuttings  







Cuttings settle as a result of inadequate hole cleaning. In horizontal and highly deviated wells, good hole cleaning is usually around the larger Drill collar OD, however cuttings can settle on smaller OD Drill pipe higher up. Cutting beds develop on the lower side of boreholes with 30 degree or greater inclinations depending upon suspension and flow rates of drilling mud. Settled Cuttings can also result in slow ROP, excessive over pull, increased torque and formation break down due to increase ECD. Hole cleaning can be controlled by:       

FIGURE 3: CUTTING SETTLING

Mud rheology modifications Flow rate Hole angle Mud weight ROP Drill pipe rotation Hole diameter

1.2 Hole Pack Off- Shale Instability A naturally over-pressured shale  It is one with a natural pore pressure greater than the normal hydrostatic pressure gradient.  Naturally over-pressured shales are most commonly caused by geological phenomena such as undercompaction, naturally removed overburden (i.e. weathering) and uplift. Using insufficient mud weight in these formations will cause the hole to become unstable and collapse.

207

FIGURE 4: NATURALLY OVERPRESSURED SHALE

Induced over-pressured shale  Induced over-pressure shale occurs when the shale assumes the hydrostatic pressure of the well bore fluids after a number of days exposure to that pressure.  When this is followed by no increase or a reduction in hydrostatic pressure in the well bore, the shale, which now has a higher internal pressure than the well bore, collapses in a similar manner to naturally over-pressured shale.

Brittle Shale  Caused by tangential stresses around the wellbore.  Tends to break free and sloughing into hole.

FIGURE 5: INDUCED OVERPRESSURED SHALE

FIGURE 6: BRITTLE SHALE

Swelling Shale  Caused by hydration processes or osmotic potential between pore fluid of shale and drilling fluid salinity.  Degree of clay hydration depends upon clay type and cat ion exchange capacity of clay.

208

Prevention  Use inhibited mud or displace to OBM.  Addition of various salts will reduce chemical attraction between shale and water.  Reduce exposure time.  Good hole cleaning.

FIGURE 7: SWELLING SHALE

1.3 Hole Pack Off- Unconsolidated Formations    

Unconsolidated formations have low cohesive strength and therefore collapse easily. Usually occur near the top hole where there is loose sand, gravel and silts. Indicated by increasing pump pressure, torque and drag. Remedy: control filtration properties of the mud ( thin filter cake) and reduce of flow rate.

1.4 Hole Pack Off- Fractured & Faulted formations    

FIGURE 8: UNCONSOLIDATE FORMATIONS

Common problem in limestone and chalk. Caused when stresses holding are released. Drill string whipping can dislodge rock fragments when drilling fractured zones. If Drill string is stuck and cannot be freed by jarring, then inhibited HCL Pill may be spotted around the stuck neck.

Formation and BHA (Well Geometry) 2.1 Key Seating 



  

Caused by rotational drill string coming in contact with soft formations. Erodes a narrow groove in the formation equal to the diameter of drill pipe tool joint. Groove created is smaller in size than BHA components below. When POOH, the BHA may be pulled into narrow sized key seat and getting stuck. Often seen in soft formations and in wells with doglegs. Doglegs and ledges provide points of contact between tool joints and walls of hole. Key seats can be easily recognized by :  Hole tight when tripping out.  Circulation is free when pipe is stuck.

FIGURE 9: FRACTURED FORMATION

FIGURE 10: KEY SEATING

209



Warning:  High angle doge leg in upper hole section.  Long drilling hours with no wiper trips through the dogleged section  Cyclic over pull at tool joint intervals on trips.



Indications:  Occurs only while POOH.  Sudden over pull as BHA reaches dogleg depth.  Unrestricted circulation.  Free string movement below key seat depth. First action:  Apply torque and jar down.  Attempt to rotate with low over pull to work through dogleg. Preventive Action:  Minimize dog leg severity to 3deg/100’ or less.  Limit over pull through suspected intervals.  Run string reamer or key seat wiper if suspected.

 

2. Lost Circulation Uncontrolled flow of whole mud into a formation. Can occur in naturally cavernous, fissured, or coarsely permeable beds, or can be artificially induced by hydraulically or mechanically fracturing the rock, thereby giving the fluid a channel to travel.

Induced Lost Circulation: o

Result of excessive overbalanced condition, where the formation is unable to withstand the effective load imposed upon it by the drilling fluid.

Naturally Occurring Losses: o Circulation lost into open fractures which are pre-existing. Can be lost into large openings with structural strength such as large pores or solution channels. Induced lost circulation

210

o The key to preventing it lies in controlling static and dynamic pressures. o Drilling fluid properties must be maintained within acceptable ranges. o Abnormal surge and swab pressures must be reduced. o All bridges must be drilled and not drove through them o Circulation must be broken cautiously o Pumping equipment must be keep in perfect conditions

o The intermediate casing must be set in a consolidated shale formation as deep as practical to ensure the highest possible fracture limit at the casing shoe Materials have been used in attempts to cure lost circulation:    

Fibrous materials, such as shredded sugar cane stalks, cotton fibers, wood fibers, and paper pulp. These materials have relatively little rigidity, and tend to be forced into large openings. Flaky materials, such as mica flakes, plastic laminates or wood chips. These materials lie flat across the face of the formation and thereby cover the openings. Granular materials, such as ground nutshells, or vitrified, expandable shale particles. Materials with strength and rigidity that when used in the correct size, seal by jamming just inside the openings. Slurries whose strength increases with time after placement, such as hydraulic cement and high-filterloss muds.

FIGURE 11: LOSS OF CIRCULATION

211

3. Well Kicks It is the entering of the formation fluid to the wellbore. This occurs when the formation pressure exceeds the hydrostatic pressure. A blowout is uncontrolled kick

Causes:     

Insufficient Mud Weight. Swabbing. Gas cut mud. Failure to keep the hole full. Lost circulation 1. Insufficient Mud Weight The formation pressure is higher than the hydrostatic pressure.  Penetration of geo pressured zone.  Accidental dilution of mud by fluid addition at surface  Dilution of mud by influx from aquifer exposed to open hole.  Gradual decrease in mud density due to gas cut and failure to degas.  Poor quality control 2. Swabbing A negative hydrostatic pressure causing reducing bottom hole pressure    

The speed of the drill pipe pulling. Mud flow properties; yield point and gel strength. Hole geometry. Balled up string.

3. Gas cut mud

212

When gas enters the mud from the formations being drilled, the mud is said to be Gascut. It is almost impossible to prevent any gas entering the mud Colom but when it does occur it should be considered as an early warning sign of a possible influx. The mud should be continuously monitored and any significant rise above low background levels of gas should be reported. Gas cutting may occur due to:  Drilling in a gas bearing formation with the correct mud weight  Swabbing when making a connection or during trips  Influx due to a negative pressure differential (formation pressure greater than borehole pressure).

4.

Failure to keep the hole full & Lost circulation  Effect of displacement: In the process of POOH the drilling string, the mud level into the well bore drops down results in the hydrostatic pressure decrease which may be followed by a flow of formation fluids into the well. Accordingly; regular filling the well in process of a round trips  Lost of Circulation: Drilling fluid could be lost while RIH the string if the pressure surges caused by string movement are high enough to create fractures. An abrupt drop of the mud level results in decrease of hydrostatic pressure followed by the flow of formation fluids into the well bore.

FIGURE 12: INDONESIA GAS BLOW OUT LOCATION , 2006

213 (Well Control Procedures Will be discussed in Well Control Chapter)

Other Hole Problems Other problems also arise which may not cause the pipe to stick but are important, such as:    

Bit balling Tight Hole Hole Wash out and erosion Hole collapse and Hole Fracture

Bit Balling   

Occurs while drilling reactive shale exhibiting plastic properties and in poorly inhibited WBM when shale particles adhere to the BHA. Can be recognized by reduced ROP as Bit cutting face is covered with cake, blocked shaker screens with clay and Overpull on trips. Remedies • Using inhibited mud systems which prevent dispersion of clay particles. • Small percentages of glycol. • Using OBM and increasing salinity.

Tight Hole     

The upward pulling force (drag) is greater than the buoyant weight of drill string. Increase in drag is a clear indication of a tight hole. Tight holes are usually be observed in reactive clays or salt. Remedies Symptoms • Increased torque • High pump pressures.

214 FIGURE 13: BIT BALLING

Directional drilling problems The maximum inclination of the well is in high range and no major difficulties are expected by the directional drilling, if cleaning considered by low viscosity follow by high viscosity, the use of steerable system will be helpful to follow the direction and avoid severe dogleg in inclination and direction. The trajectory of the well should be carefully monitored in order to avoid risks of collision with existing wells of the same field especially in first 500-m Drilling problems associated with direction well drilling and their remedy There are five main problems during drilling horizontal wells and drain holes, namely:     

Delivering weight to the bit. Reducing torque and drag forces. Hole cleaning. Protection of water sensitive shale. Directional control

1. Delivering weight to the bit:Applying sufficient bit weight for optimum drilling rate that is often a problem, especially at higher angles and while drilling a horizontal section. Conventional bit weight for efficient drilling is a bout 2000-5000 lbf. Per inch of bit diameter. Motor assemblies drill efficiency with less bit weight then rotary assemblies, they compensate for bit weight with higher rotational speed of turbines and motors. Remedy:Bit weight may be increased by reducing drag and torque by using the split assembly, including the bit, motor, directional control tools, and the nonmagnetic collars, which left at the bottom of the drill string.

215

2. Reducing torque and drag forces:Drag is a force restricting the movement of the drill tools in directions parallel to the well path. Torque is the force resisting rotational movement. Drag and torque are measurements of this frictional resistance to the movement of the drill tools. Excess drag and torque cause directional drilling problems, especially in the turning and horizontal sections of horizontal well often very severe in this well. The drill string can be failed from tension due to excess drag or twist off duo to excess torque. REMEDY:Eliminating all drag and torque is not practical , but preventive actions reduce them to an acceptable levels , it is best to design the well pattern for a minimum number of changes of angle and a low angle of build or drop . Excess drag and torque is reduced pipe placing casing in the hole. Reaming reduces drag and torque caused by key seats and rough wellbore, reducing drill string weight reduces drag and torque at high quality of mud with good chemical and physical properties. Oil base mud should be considered for more demanding situations because of its good lubricating qualities.

3. Hole cleaning or cutting removal:A particular problem that arises in the drilling horizontal wells is the difficulty of removing rock cuttings from the horizontal section of the well. The source of the problem is that cuttings tend to settle in the bottom of the hole and increase the friction in the hole, produce poor cement bonds.

216

REMEDY A great improvement in removing cuttings has been an achieved by using top drive drilling rigs. In these rigs, the drill string is rotated by a large, geared electric or hydraulic drive motor rather than by the conventional rotary table and Kelly. With this arrangement, it is possible to rotate the drill string and to circulate mud as removed from the hole. This tends to keep the drill cutting in suspension and to provide a cleaner hole, the removal of cuttings reduces friction between the drill pipe and the hole and reduces the tendency for sticking.

4. Protection of water sensitive shale:Shale layer frequently tend to collapse in contact with fresh water, this can be prevented by using oil based drilling fluid, which usually consist of an invert emulsion of water in diesel oil together with other additives REMEDY:Water -base mud can be inhibited to reduce the attack on water- sensitive shale by addition of NaCl or CaCl2 . These additives reduce the chemical activity of water and its tendency to penetrate into the water-sensitive shale .

5. Directional control:Overcoming the force of gravity is a fundamental problem in directional and horizontal drilling. The bottom hole assembly (BHA) is a heavy weight hanging on the bottom of the drill string. The BHA must overcome the force of gravity with a strong side force for directional drilling. REMEDY:A adjustable assemblies are more flexible for use in various situations, specially the steerable versions (the term steerable has a special meaning in the oil industry), the steerable BHA consists of bit, down hole motor with build in dog-leg tendency, measurement-while drilling (MWD).

217

Problems Encountered during Underbalanced Drilling

FIGURE 14: PROBLEMS OF UBD WELLS

Here are some of the general problems of UB drilling. All of them are not always found in every hole:

1. Well Bore Collapse

218

Two general categories of wellbore instability may be encountered while drilling:  Mechanical instability  Chemical instability.

Mechanical instability includes situations where the fluid density is not sufficient to keep the formation in question from falling or caving into the hole. The formation is driven into the borehole by pressure trapped in the formation. The pressure may be the result of tectonically induced stress or abnormal pressure. It also may simply be due to poor cementation of the rock particles (e.g., unconsolidated sandstone). Chemical instability is the result of a chemical reaction between the formation and the fluid in the wellbore. A good example is the reaction between waterbased drilling fluids and a water sensitive shale or clay in the formation. The surface indications of wellbore instability are very much the same, regardless of the type of instability. They include:  High torque  Increased drag  Fill on connections  Difficulty in pulling off bottom, or in pulling the first few stands  Pressure increases when circulation begins, then decreases once circulation is well underway If the problem is mechanical in nature, for example, large cuttings in the wellbore, the problem may seem to move around or be encountered in a different place each time.  There may be no difficulty in circulating.  Movement downward may be possible, while upward movement of the pipe is not, and the tight spot may appear in a different place each time it is encountered.  Prevention of mechanical instability may mean that underbalanced drilling cannot continue. Drilling fluid density may have to be increased to the point where formation pressure is lower than wellbore pressure, as in conventional drilling. The first solution to implement when a mechanically unstable formation is encountered is to increase the circulation rate. Large cuttings require high air rates for removal. If the cuttings are very large, air or gas will not lift them from the wellbore. They will have to be ground until they are small enough to be lifted out. Working the pipe will help grind these cuttings. The problem of instability may be mitigated by adjusting the liquid injection rate to ensure the fluid is in the stable foam regime. Foam will lift cuttings much better than either pure gas or pure liquid. Prevention of chemical instability will require a good knowledge of the mineralogy of the formations being drilled. Inhibitive or nonreactive fluids can be used for drilling. Fortunately, probably the most non-reactive fluid available is air.

219

2. Corrosion Problem Corrosion is the destruction of metal by chemical or electrochemical action between the metal and its environment. i.e.: Corrosion occurs as a result of interaction between iron steel of drill string and water base mud. Four conditions must be met ,however , before wet corrosion: 1. Anode and cathode must exist. 2. The anode and cathode must be immersed in electrolytic medium. 3. A potential difference between anode and cathode exists. 4. There must be a coupling to complete the electrical circuit. o The anode and cathode exist on the drill pipe itself. o The drilling mud may serve as electrolytic medium. o The coupling is creating by the drill pipe steel. o The potential difference is due to the crystalline structure and different metal used in the drilling pipe alloy. Factors affecting corrosion rate 1. Oxygen:   

Oxygen reacts with metal of drill string forming (Fe2O3 & Fe3O4), which accelerates corrosion on metal. Oxygen acts to remove protective films on drill string which accelerate corrosion action and increase pitting deposits (reddish brown rust of Fe(OH)3 . Oxygen scavengers, passivating inhibitors and filming inhibitor treatments are used to mitigate oxygen corrosion attack.

2. H2S: Fe + H2S

FeS + 2H+

The increase of H+ atoms in mud will result in retaining acidic medium which will increase corrosion effect. H2S, cause severe pitting embattlement and stress cracking also a black sulfide coating. 

Treat with sulfide scavenger as ZnO. Also Film-forming inhibitors are used.  Keep pH between 8-9. 3. CO2:

220

CO2 is an acidic gas that results in pH reduction and thus increases corrosion effect and pitting attack. CO2 + + H2O

H2CO3 (Carbonic acid).

H2CO3 + Fe

FeCO3 +H2.

i.e.: FeCO3 deposits indicate CO2 attack.   

Increase Mwt to stop gas influx. Keep pH between 8-9. Add filming amine

4. Bacteria:  

The by-product of bacteria are CO2, H2S and SO4(leads to H2SO4). Microiobacids are used to control bacterial effect in drilling environments.

5. Dissolved Salt: As salt concentration increases, conductivity between charge poles raises also electrical resistance of drilling fluid decreases.

6. Velocity of Drilling Fluid: The higher the mud velocity the higher the rate of erosion of films around the drill string and thus the higher the rate of corrosion (Treat with oil mud, amines).

7. Temperature: Rule of thumb : Corrosive rate doubles with every 55 ft increase. As the increase of temperature increases the solubility of corrosive gases (O2, H2S & CO2).

8. Pressure: The increase of pressure causes an increase in trapping effect of gases in mud such as O2 and thus causes increase in corrosion effect.

9. pH: Corrosive is much slower in alkaline medium than in acidic medium. So corrosive rate decreases as pH increases. NB: The best medium of pH to minimize corrosion rate is a pH between 8.5-10.

10. Solids: Increase of abrasive solids in mud accelerates removal of protective film around drill string due to increase of friction action causing pipe washout.

221

Also removal of protective film helps corrosive elements attack to drill string steel and thus accelerate corrosion rate. Corrosion Control     

Keep pH above 9 Steel becomes passive above pH = 11 Don’t use air. Oxygen corrosion is the most common type of corrosion. There are other types of corrosion and scaling.

Corrosion Inhibitors

3. Problems with Gas Drilling      

Water. Washouts, especially in coal. Corrosion. Downhole fires with air. Crooked hole. Vibration

Water The big problem with air drilling is water in the formations. Some of the worst shales will drill dry very well, but once water is added will slough. Water generally also means increased gas or air volume.

Washouts Washouts, which make it difficult to lift the cuttings out of the hole, are very common in fractured or broken coal beds

Corrosion With the addition of water comes the problem of corrosion

Downhole fires with air. Down hole fires occur when drilling into light oils with air

222

TABLE 1: PROBLEMS OF UBD SYSTEMS

Drilling Method or Fluid System

Problems and/or Potential Expenditures Possible problems if water flow is encountered Hole erosion, if poorly consolidated.

Air

Possibility of downhole fire, if hydrocarbons are encountered. Supplementary equipment rental. Is not suitable for H2S Problems if water flow is encountered. Hole erosion, if poorly consolidated.

Gas (Nitrogen or Natural Gas )

Cost is high if a market for the gas exists. Rig safety. Supplementary equipment rental If H2S is expected, consider a closed system. Problems if substantial water flow is encountered. Gas Cost if air not used. Hole erosion, if poorly consolidated.

Mist

Shale stability.

Disposal of waste water/gas and supplementary rental cost. Air-mist not suitable if H2S is present Stiff Foam Fluid degradation possible if oil, salt water or calcium

Gasified Liquids

Corrosion potential (and requirement for inhibitors 62) is air is used.

223

Problems Encountered during Drilling Obayed Field 1. Drilling 17 1/2” Surface hole Potential Problems and Drilling Issues         

Partial/Total losses in Moghra (40 – 70 bbl's/hr) Heaving / swelling clay in bottom of Moghra Unstable shale in Dabaa (a lot and repeatedly caving shale), possible stuck pipe and high tendency of hole pack off. Hole filling by accumulation of drilled cuttings Difficulty running casing Losses with cement displacement during 13 3/8” cement job (130 bbl) May be Top hole cement fill is required. Formation erosion below cellar (confirm to drill mouse hole and fill conductor with betonies mud not water) Bit and Stabilizer balling up.

2. Drilling 12 1/4” Hole Potential Problems and Drilling Issues   

Partial losses in ABOU ROASH A-F. Hole filling by accumulation of the drilled cuttings Losses with cement displacement during 9 5/8” cement job

3. Drilling 8 ½” hole Potential Problems and Drilling Issues  

224

Insufficient kick tolerance: Leak-off test at 9 5/8” shoe must be conducted to confirm the shoe strength is sufficient to drill. Losses: total losses have been experienced due to depletion in the lower safa

4. Drilling 6” Hole Section Potential Problems and Drilling Issues 

Problems with hole cleaning may be expected. Frequent sweeping of the well with low/high viscous pills will be required. Careful monitoring of drag during tripping is required to identify the presence of cutting beds.

 

Uncontrollable losses to open fractures Poor hole cleaning. Insufficient flow rates, poor mud properties

5. Drilling 3 7/8” Hole section Potential Problems and Drilling Issues (full description)



3 7/8” hole was drilled from 4185 to 4190 m. Damage was noted to the 2 7/8” NRV’s (rubber seal) and to the MWD tools. The probe centraliser had de-bonded and worn and the impeller bearing rubber was 90% eroded. It was assumed that the rubber goods were reacting with the amine in the fluid system (This has not been proved at the time of writing). The amine was subsequently removed for future runs.



the well was re-logged from 4200 to 4208 m. Drilling continued from 4208 to 4210 m, Drilling recommenced (45 minutes NPT) from 4210 to 4221 m at 2 -3 m / hr: The LWD / MWD failed at 4221 m (dynamic bottom hole temperature measured at 147 degrees Celsius).



LWD / MWD after trouble shooting continued to pulse, slide drilling continued to 4224 m (ROP 0.8 m / hr). Turbine wear was measured at 2 mm and was found to have a damaged crossover (downhole over torquing). LWD / MWD rubber elements were again found to be damaged.



The BHA was run into the well and washed down from 4079 to 4224 m. A survey attempt failed and the pulsar would only transmit temperature data. Drilling commenced (blind) from 4224 to 4243 m. A gradual drop in standpipe pressure (1500 psi) was observed; surface checks confirmed the pressure loss was down hole. Torque increases, poor

225

ROP and high torque and drag were noted. It was decided to end the bit run. On surface it was noted that the Bit had experienced significant wear. 

On surface it was observed that the MWD pulser sub had washed out in two places.



The BHA was picked up and tested on surface (new MWD / LWD, rerun Turbine). The BHA was run into the well to 670 m and an attempt was made to circulate. The SPP had to be brought up to 1800 psi to achieve circulation. The trip in hole continued (filling the string every twenty stands).



The BHA was picked up and tested on surface (new MWD / LWD, rerun Turbine). The BHA was run into the well to 670 m and an attempt was made to circulate. The SPP had to be brought up to 1800 psi to achieve circulation. The trip in hole continued (filling the string every twenty stands), to 4000 m where 20 klbs drag was seen and an attempt to circulate was made. Due to the inability to circulate, the line up of the choke was rechecked and was found to be closed in downstream. The geolograph showed that the weight of the string had been decreasing for the previous four stands prior to breaking circulation. Therefore it is presumed that it is at this stage the choke was closed (or downstream valve) and the well was then over pressured to 2000 psi. The cause of this was due to human error, due to a lack of detailed job specific procedures (in our own opinion that is what lead to the failure of the project)



The trip continued after breaking circulation to 4209 m, the well was unloaded (200 scf / m N2 and 80 gpm inhibited water). During the unloading of the well the data acquisition system failed again (7.5 hours NPT).



226

After repairing the system the trip continued from 3355 to 4142 m, the BHA was then washed down to 4180 m where the well was unloaded (200 scf / m N2 (increased to 300 scf / m) and 80 gpm inhibited water). After unloading, the trip continued to 4243 m (washing down) and drilling

continued (300 scf / m and 90 gpm inhibited water). Drilling continued from 4243 to 4266 m at which point the MWD / LWD tool failed (highest temperature recording 152 degrees Celsius). 

As it was clear from the previous drilling that no hydrocarbons were being produced from the reservoir, the risk of drilling without the PWD to monitor BHP was deemed acceptable. The run was primarily to prove the viability of the whole system, without considering the shortcomings caused by the MWD / LWD failures.



The BHA was picked up and tested on surface (no MWD / LWD), two BHA NRV’s were replaced and the assembly was run in the well. Circulation was broken every 20 stands. The BHA was run to 4185 m, no pressure was seen below the DDV (NB. The DDV open control line would not hold pressure). The well was unloaded (400 scfm / 80 gpm inhibited water).



The trip continued to 4347 m where resistance (15 klbs) was noted, the BHA was washed down from this point to 4277 m. Rotary drilling commenced from 4277 to 4375 m ( 650 scfm / 85 gm). A slide drilling test was done from 4375 to 4378 m. At this point the turbine stalled and the SPP increased to 3600 psi. Attempts to bleed off pressure and regain circulation were unsuccessful; therefore it was decided to trip out of the well.



Returns from the string were seen throughout the trip out of the well. Upon inspection at the surface it was found that the two NRV’s above the turbine had failed. TD of the well was called at this point due to MWD / LWD unavailability.

227

Corrosion plan for UB Obayed filed  Corrosion is a major concern every time that gasified fluids are utilized in oil and gas wells drilling. It is particularly a concern when oxygen in small or big volumes is injected in salt based fluids. One of the aims of any drilling project should be to minimize corrosion. This is first defined by setting goals for drill string corrosion rates, defined in mils of metal lost or dissolved per year (mpy) as measured by ring coupons and/or corrosometers. (1 mil = 1/1000 inch)  Drilling wells underbalanced in the Obaiyed field, challenged Weatherford engineering to design an effective fluid system able to control corrosion over steel components downhole. In Obaiyed wells, all conditions are given to create a highly corrosive environment. Conditions such high depth, high temperature, high salinity in the produced waters, the utilization of fresh water as drilling fluid, significant presence of H2S and CO2 and membrane Nitrogen injection yields an explosive corrosive cocktail. This document contains a corrosion plan designed to minimize corrosion levels given the demanding conditions of the upcoming wells in Obaiyed. Different companies have different levels of tolerance with respect to corrosion. For the present application corrosion rate less than 50 mpy or 2 lbs/ft2 per year with no pitting is considered to be acceptable.

The Primary corrosion control system consists of:   

228

Adjust pH-to-pH 9.9 + with caustic soda (sodium hydroxide). Use CorrFoam 1 @ 7200 ppm or 7.2 gallons per 1000 gallons or 0.3 gallons per barrel of water. Use WFT C-100 @ 7200 ppm or 7.2 gallons per 1000 gallons or 0.3 gallons per barrel of water.

NOTES:  Batch mix the C-100 based on fluid volume  Batch mix CorrFoam 1 initially at recommended concentration and keep continuous injection while drilling using chemical pumps at rates recommended by corrosion Engineer on site.  Maintain a minimum of 50 ppm as PO4 by standard Taylor phosphonate kit.  Monitor chlorides carefully.  Monitor corrosion rate with rings to < 2 lbs/ft 2/year.  As CO2 is encountered add lime as needed to control pH, near or about 1% of weight or about 3.5 ppb.  As produced water is encountered or any heavy CO2 returns, watch the chlorides level.

Secondary Corrosion control system: If salinity approaches the formation water of 180,000 ppm as NaCl, consider the following:  Start additions of WTF 9812 at 1% (10000 PPM)  Maintain the C-100 and the CorrFoam-1 rates. Alternative system: If corrosion levels are still above permitted level (< 2 lbs/ft 2/year) Alternatively switch the system to:   

CorrFoam 1(corrosion inhibitor): 0.5%(5000 ppm) WTF 9368 (corrosion inhibitor): 05% (5000 ppm) WTF 9812 (H2S scavenger): 1.0% (10,000 ppm)

Conclusions: 

The systems recommended are based on Weatherford’s experience of proven chemical techniques.  The concentrations recommended follow this success for the C-100 and the CorrFoam 1.  The additional process of using the CorrFoam 1, WTF 9368, and WTF 9812 generating an insitu complex are patent pending developed for high temperature systems, containing air, CO2, and H2S. It is still being determined to use WTF 9812 with C-100/CorrFoam 1 for similar effect at temperatures lower than 450F

229

Chemicals Added

Gas rate

Fluid Rate

Corrosion Rate

Phosphate

Sulphide

Iron

SG

Alkalinity

CL

BS&W

ph

Date

Fluid Summary

7/26/05

1 x CorrFoam 1-9323 1 x C100-9386 2 x Ai6009368

7/27/05

1 x CorrFoam 1-9323 1 x C100-9386 2 x Ai6009368

7/28/05

1 x CorrFoam 1-9323 1 x C100-9386 2 x Ai6009368 2 x CorrFoam 1-9323 7/29/05

1 x C100-9386 9.8

N/D

7500

350

0

N/D

3000

110

0

2 x Ai6009368 2 x Alpha 19812 1 x CorrFoam 1-9323

7/30/05

1 x C100-9386 9.8

N/D

7000

400

5

N/D

1500

N/D

110

0

2 x Ai6009368

230

7/31/05

1 x Alpha 19812 1 x Caustic Soda 1 x Lime

9.2

N/D

8000

>500

8.4

40

0

200

2.6 / 1.52

3000

0.38 / 0.44

600

0.23 / 0.07

5 x CorrFoam 1-9323 110

500

3 x C100-9386

8/5/05

8/4/05

8/3/0 5

8/2/05

8/1/0 5

1 x Alpha 19812

9.6

11

N/D

N/A

15000

1000

>500

>501

8.5

8.4

10

0

0

0

0

0

0

1 x CorrFoam 1-9323

0

5 x CorrFoam 1-9323

2 x CorrFoam 19323

8/8/05 8/9/05 8/10/05

10 x CorrFoam 1-9323

Chemicals Added

400

Gas rate

85

Fluid Rate

4000

4.38 / 4.22

Corrosion Rate

Alkalinity

0

Phosphate

CL

8.4

Sulphide

>500

Iron

3700

SG

N/A

BS&W

ph

9.4

800 / 25

8/7/05

Date

8/6/05

Built 1000 bbls of new fluid at request of Bapetco. Bapetco had concerns about potential incompatibilities b/w the Elastomer components of the MWD / NRV and the amine component. New fluid only contains WFT 9323 with lime to PH 10.5 (10 sx lime).

No activity

9.6

N/A

4000

>500

8.4

80

0

6000

4.68 / 0.05

90

300

4 x CorrFoam 19323

No activity

231

8/11/05

4 x CorrFoam 19323 2 x Alpha 1-9812

8.4

25

0

6000

90

300 4 x Alpha 2325 (defoamer) 2 x CorrFoam 19323

1.91 / 2.54

90

1.91 / 2.54

90

300

1 x CorrFoam 19323

90

300

2 x CorrFoam 19323

8/13/05

>500

9.1

8/14/05

5000

10.1

N/A

4800

>500

8.4

100

0

4000

8/15/05

N/A

1 x CorrFoam 19323

9.25

N/A

3240

>500

8.4

75

0

5000

8/16/05

9.85

4.68 / 0.05

9.7

N/A

4050

>500

8.4

75

0

4000

1.38 / 0.61

80

650

5 x CorrFoam 19323

8/17/05

8/12/05

WFT 9323 corrosion inhibitor added while circulating. Emec lubricant was added, no incompatibilities were noted in bottle tests. The EMEC lube is derived from sulphur chemistry. And therefore R&D recommended the use of WFT-9812 H2S Scavenger to prevent potential H2S generation.

9.8

N/A

3800

>500

8.4

10

0

6000

0.27 / 2.35

80

650

2 x CorrFoam 19323

4800

>500

8.4

100

0

4000

300 4 x WFT Alpha 1-9812

8/18/05

N/A

232

8/19/05

9.8

N/A

4000

>500

8.4

4

0

3800

2.26

50

1000

2 x CorrFoam 19323

8/20/05

No sample taken

9.8

N/A

4000

>500

8.4

4

0

3800

2.26

50

1000

No sample taken

References Weatherford Catalogue (2000) "Drilling & Intervention Services".

Baker catalogue (2000) "Fishing Services".

Bourgoyne et al (1986) "Applied Drilling Engineering" SPE Text books

Adam, N. (1977). How to control differential pipe sticking. Petroleum Engineer, Oct. Nov. Dec.

Brouse, M. (1982, 1983). How to handle stuck pipe and fishing problems. World Oil, Nov. Dec. 1982, Jan. 1983.

Schlumberger (1977). Sit-back off. Schlumberger Publication

233

234

WELL CONTROL T

his

chapter

will

introduce

the

procedures

and

equipment used to ensure that fluid (oil, gas or water) does not flow in an uncontrolled way from the formations being drilled, into the borehole and eventually to surface in conventional drilling, coiled tubing drilling and underbalanced drilling. This flow will occur if the pressure in the pore space of the formations being drilled (the formation pressure) is greater than the hydrostatic pressure exerted by the column of mud in the wellbore (the borehole pressure). It is essential that the borehole pressure, due to the column of fluid, exceeds the formation pressure at all times during drilling.

CONTENT

WELL CONTROL IN UNDERBALANC ED DRILLING

In Underbalanced Drilling

1- WELL Control PRINCIPLES 2- Causes of Primary control loss 3- WARNING INDICATORS OF A KICK 4- SECONDARY CONTROl 5- Blowout Prevention (BOP) EQUIPMENT 6- Coiled tubing BOP stack arrangements

235

Well control definition  

         

A kick is defined as an unwanted influx of formation fluids into the wellbore A blowout is defined as an uncontrolled flow of formation fluids to the surface or to another formation underground (underground blowout). It is Loss of control of a kick. It can be at surface or underground and caused by equipment failure or human error. Hydrostatic pressure is the pressure exerted by the column of mud at rest or in static condition. Pressure gradient express the pressure exerted by the fluid in terms of psi/ft of depth Formation pressure it is the pressure contained in the pore space of the formation or the pressure contain in the formation fluid. Normally pressured formation is one in which the formation pressure is equal to the hydrostatic pressure of fluid above the zone of interest. Abnormal pressure formation is a formation of greater gradient due to the trapping of formation fluid in place during compaction (not allowed to be escaped) Overburden pressure is the pressure exerted on formation by weight of the rock and fluids above the zone of interest. Fracture pressure is the pressure required to fracture a given formation. Or the pressure required causing the formation to fail and split. Surge or swap pressure: pressure result from the movement of drill string in or out of the hole. Shut in drill pipe pressure is measure of the difference between the pressure downhole and HSP in the drillpipe when shut in the well. Shut in casing pressure is measure of the difference between formation pressure and HSP in the annulus when shut in the well.

236 FIGURE 1: PRESSURE DISCRIPTION

WELL Control PRINCIPLES There are basically two ways in which fluids can be prevented from flowing, from the formation, into the borehole:

Primary Control

Secondary Control Secondary control is required when primary control has failed (e.g. an unexpectedly high pressure formation has been entered) and formation fluids are flowing into the wellbore. The aim of secondary control is to stop the flow of fluids into the wellbore and eventually allow the influx to be circulated to surface and safely discharged, while preventing further influx downhole.  

The first step in this process is to close the annulus space off at surface, with the BOP valves, to prevent further influx of formation fluids. The next step is to circulate heavy mud down the drillstring and up the annulus, to displace the influx and replace the original mud (which allowed the influx in the first place).

Causes of Primary control loss


Primary control over the well is maintained by ensuring that the pressure due to the column of mud in the borehole is greater than the pressure in the formations being drilled i.e. maintaining a positive differential pressure or overbalance on the formation pressures.

Reduction in Mud weight

The mud weight is generally designed such that the borehole pressure opposite permeable (and in particular hydrocarbon bearing sands) is around 200-300 psi greater than the formation pore pressure. This pressure differential is known as the overbalance. If the mud weight is reduced the overbalance becomes less and the risk of taking a kick becomes greater.

237

The mud weight will fall during normal operations because of the following:  

Solids removal: If the solids removal equipment is not designed properly a large amount of the weighting solids (Barite) may also be removed. Excessive dilution of the mud: When the mud is being treated to improve some property (e.g. viscosity) the first stage is to dilute the mud with water (water-back )in Gas cutting of the mud: If gas seeps from the formation into the circulating mud (known as gas-cutting) it will reduce the density of the drilling fluid.

Reduced Height of Mud Column During normal drilling operations the volume of fluid pumped into the borehole should be equal to the volume of mud returned and when the pumps are stopped, the level of the mud fall below the mud flowline. If the top of the mud drops down the hole then the height of the column of mud above any particular formation is decreased and the borehole pressure at that point is decreased

The mud Colum height may be reduced by;  



Tripping: The top of the column of mud will fall as the drillpipe is pulled from the borehole when tripping. Swabbing: is the process by which fluids are sucked into the borehole, from the formation, when the drillstring is being pulled out of hole. This happens when the bit has become covered in drilled material and the drillstring acts like a giant piston when moving upwards (The opposite effect is known as Surging) Lost circulation: occurs when a fractured, or very high permeability, formation is being drilled. Whole mud is lost to the formation and this reduces the height of the mud colom in the borehole.

238 FIGURE 2: TRIP TRANK CONNECTED TO BOP STACK TO CLOSELY MONITOR THE VOLUME OF THE MUD REQUIRED FOR FILL UP

WARNING INDICATORS OF A KICK Types of kick  Rapid expansion as gas circulated through choke  Mud gas separators and flare lines used to kick off the well.  Gas migration problems  Higher SICP than others  Barite settling in OB mud  Solubility of gas masks kick indicators  Flammability of gas  Slugging of gas at choke  Oil Kicks  Flammable but not as explosive as gas  Density greater than gas-lower SICP  Very little expansion as kick reaches surface  But, there is almost always some gas present  Water kicks  not flammable  very little expansion  lower SICP than gas or oil  But, there is still usually some gas present.

Primary Indicators of a Kick The primary indicators of a kick are as follows:  Flow rate increase FIGURE 3: KICK OCCURANCE  Pit volume increase  Rate of penetration increases  Change in shape and size of cuttings  Increase in rotary torque and drag  Increase in flow line temperature  Decrease in shale density  Increase in chloride content  Flowing well with pumps shut off  Improper hole fill up during trips


 Gas Kicks

Shut in Procedure When a kick is detected while tripping: 1. 2. 3. 4.

Set the slips below the top tool joint Stab a full opening safety valve(e.g. TIW valve), and close it Open the HCR valve and close the BOPs and choke. Pick up and stab the Kelly or a pump-in line

239

5. Open the safety valve 6. Notify the supervisor 7. Read & record SIDPP, SICP, pit gain and time 8. Prepare to implement kill procedures When an influx has occurred and has subsequently been shut-in, the pressures on the drill pipe and the annulus at surface can be used to determine:  The formation pore pressure  The mud weight required to kill the well  The type of influx

240 FIGURE 4: SHUT IN THE WELL OPERATION

Well killing procedures The driller Method:  The method procedures are: 1. Shut the well in after a kick is recognized 2. Record the shut in drill pipe and shut in casing pressures 3. Circulate the kick out of the hole 4. Shut the well in a second time to build the mud weight up to the kill mud weight 5. Circulate the well with the heavier mud

FIGURE 5: SIX WELL KNOWN COMMON METHODS

Wait and weight Method: It is widely used in hard rock area and in some cases it can cause lost circulation and formation breakdown  The method procedures are: 1. Shut the well in after a kick is recognized 2. Record the shut in drill pipe and shut in casing pressures till stabilization condition 3. Calculate the kill mud weight required as the following: Pdp k  m  0.052  d 4. Adopt the existing mud weight with adding barite until the kill weight is achieved 5. Calculate the total volume of the drill string and all annuli 6. Calculate the number of pump strokes required to pump down the calculated new mud volume


The method involved circulating the kick out of the hole, then second and third circulation of kill weight mud.

241

= mud volume (bbl) / stroke capacity (bbl/stroke) 7. Calculate the pumping time = No of strokes/ 30 spm 8. Pump the mud down hole to control the formation pressure 9. When the new mud is pumped down hole it is heavy enough to replace the shut-in pressure

Circulate and weight method The circulate and weight method utilizes the advantages of both the wait and weight method and the driller's method. Instead of shutting in the well long enough to weight up to kill weighted Mud (KWM), the well is shut in only long enough to measure the shut in pressures and pit gain. Next circulation is started from the suction pit with the original weight mud, at initial circulating pressure, as in the driller's method. While circulating with original weight mud, a separate pit of mud is being weighted up to KWM. As soon as the KWM is reached, we begin to circulate from the pit of KWM following the procedure set out for the wait and weight method starting at step number 4. This procedure has the advantages of a short shut in period, lower casing pressures, and fast kill times.

Reverse circulation method Reverse circulation procedures are most often used during workover and completion operations. Reverse circulation requires lining the pumps up on the annulus, circulating down the casing side, and up the drill pipe, work string, or tubing. This method is sometimes used when killing a producing well where the production choke is used instead of an adjustable choke. If the packer fluid is of sufficient density to control formation pressure, reversing out the tubing volume is all that is required to kill the well.

Bullheading Bullheading is the term used to describe pumping the wellbore fluids back into the formation. Pumps are tied in at the surface, and kill fluid is pumped into the well until the well if full of the proper kill weight fluid. Often times during Bullheading, the formation is fractured, and it becomes difficult to keep the well full of fluid. Bullheading is most often used during workover operations, mainly because it is simple and requires little or no planning.

242

With a high fluid loss fluid (brine waters, or formation fluids) it is possible to pump into open formations without fracturing the formation, if there is a relatively permeable formation and care is taken while pumping. Low fluid loss fluids such as drilling mud or frac fluids will tend to develop a filter cake and seal off the pore spaces (as they are designed to do), which means that the formation will have to be fractured in order to pump fluid into it.

A pressure decline schedule can be developed for a Bullheading procedure by the following:  Initial pump in pressure= (frac gradient, ppg-Mud weight ppg)*0.052*TVD  Final pump in ppg)*0.052*TVD

pressure=(frac

gradient,

ppg-kill

weight

mud,

FIGURE 6: CONSIDERATION FOR BULLHEADING

Volumetric method The volumetric method is utilized in the event of gas migration in a shut in well, usually when we cannot circulate for some reason, whether it is due to power failure, plugged drillstring, or the pipe is out of the hole. With the volumetric method, we allow the gas bubble to expand as it migrates up the wellbore, to avoid excessive surface pressures associated with gas migration. We calculate the annular capacity in bbl/ft at the depth of the gas bubble, and determine the HSP imposed per barrel of mud. As the bubble migrates toward the surface the shut in pressures will increase, since the BHP is also increasing we can bleed off the excess surface pressure. If we bleed off too much mud, we will allow an additional influx into the well. As we bleed mud from the wellbore, the HSP is decreasing resulting in an increase in required surface pressure. By calculating the HSP per barrel of mud, we know how much the surface pressure will increase for each barrel of mud bled from the well. The surface pressure increase will be equal to the HSP of the mud that was bled off.


Theoretically, the pressure will decline from the initial pump in pressure to the final pump in pressure in the time it takes to pump kill weight fluid from the surface to the zone of interest.

243

FIGURE 7: VOLUMETRIC TECHNIQUE

Blowout Prevention (BOP) EQUIPMENT The blowout prevention (BOP) equipment is the equipment which is used to shut in a well and circulate out an influx if it occurs. The main components of this equipment are the blowout preventers or BOP's

There are 2 basic types of blowout preventer used for closing in a well:  Annular (bag type) or  Ram type. It is very rare for only one blowout preventer to be used on a well. Two, three or more preventers are generally stacked up, one on top of the other to make up a BOP stack.

Annular Preventers It is a high tensile strength, circular rubber packing unit. The rubber is moulded around a series of metal ribs. The packing unit can be compressed inwards against drillpipe by a piston, operated by hydraulic power. The advantage of such a well control device is that the packing element will close off around any size or shape of pipe. An annular preventer will also allow pipe to be stripped in (run into the well whilst containing annulus pressure) and out and rotated, although its service life is much reduced by this operation

244

Ram Type Preventers Ram type preventers derive their name from the twin ram elements which make up their closing mechanism. Three types of ram preventers are available:

  



Blind rams - which completely close off the wellbore when there is no pipe in the hole. Pipe rams - which seal off around a specific size of pipe thus sealing of the annulus. In 1980 variable rams were made available by manufacturers. These rams will close and seal on a range of drillpipe sizes. Shear rams which are the same as blind rams except that they can cut through drillpipe for emergency shut-in but should only be used as a last resort. A set of pipe rams may be installed below the shear rams to support the severed drillstring. Slip ram which can hold full weight without damage and allow pulling up of string to the surface, it is usually applicable in coiled tubing drilling.


FIGURE 8: ANNULAR PREVENTOR

245

FIGURE 9: RAM PARTS

Drilling Spools A drilling spool is a connector which allows choke and kill lines to be attached to the BOP stack.

Casing Spools The wellhead, from which the casing strings are suspended are made up of casing spools.

Tubing Spool It is double flange spool from which the tubing strings are suspended.

Choke and Kill Lines When circulating out a kick the heavy fluid is pumped down the drillstring, up the annulus and out to surface. Since the well is closed in at the annular preventer the wellbore fluids leave the annulus through the side outlet below the BOP rams or the drilling spool outlets and pass into a high pressure line known as the choke line. The choke line carries the mud and influx from the BOP stack to the choke manifold. The kill line is a high pressure pipeline between the side outlet, opposite the choke line outlet, on the BOP stack and the mud pumps and provides a means of pumping fluids downhole when the normal method of circulating down the drillstring is not possible.

Choke Manifold The choke manifold is an arrangement of valves, pipelines and chokes designed to control the flow from the annulus of the well during a well killing operation. It must be capable of:

246

 Controlling pressures by using manually operated chokes or chokes operated from a remote location.  Diverting flow to a burning pit, flare or mud pits.  Having enough back up lines should any part of the manifold fail.

The mud/gas separator The mud/gas separator is designed to provide effective separation of the mud and gas circulated from the well by venting the gas and returning the mud to the mud pits. Small amounts of entrained gas can then be handled by a vacuum-type degasser located in the mud pits. The mud/gas separator controls gas cutting during kick situations, during drilling with significant drilled gas in the mud returns, or when trip gas is circulated up.


FIGURE 10: CHOKE MANIFOLD

247 FIGURE 11: MUD - GAS SEPARATOR

Choke Device A choke is simply a device which applies some resistance to flow. The resistance creates a back pressure which is used to control bottomhole pressure during a well killing operation. Both fixed chokes and adjustable chokes are available. The choke can be operated hydraulically or manually if necessary.

FIGURE 12: REMOTE ADJUSTABLE CHOKE

Hydraulic Power Package (Accumulators) The opening and closing of the BOP’s is controlled from the rig floor. The control panel is connected to an accumulator system which supplies the energy required to operate all the elements of the BOP stack. The accumulator consists of cylinders which store hydraulic oil at high pressure under a compressed inert gas (nitrogen). When the BOPs have to be closed the hydraulic oil is released (the system is designed to operate in less than 5 seconds). Hydraulic pumps replenish the accumulator with the same amount of fluid used to operate the preventers

248

FIGURE 13: KUMMY UNIT

ACCUMULATOR

Internal Blow-out Preventers

A float valve installed in the drillstring will prevent upward flow, but allow normal circulation to continue. It is more often used to reduce backflow during connections. One disadvantage of using a float valve is that drill pipe pressure cannot be read at surface. A manual safety valve should be kept on the rig floor at all times. It should be a full opening ball-type valve so there is no restriction to flow. This valve is installed onto the top of the drillstring if a kick occurs during a trip. Kelly cock valve installed at one or both ends of the Kelly. When a highpressure backflow occurs inside the drill stem, the valve is closed to keep pressure off the rig floor.

FIGURE 14: KELLY COCK & DROP IN CHECK VALVE

An example of the API code (API RP 53) for describing the stack arrangement is:


There are a variety of tools used to prevent formation fluids rising up inside the drillpipe. Among these are float valves, safety valves, check valves and the Kelly cock.

5M - 13 5/8" - RSRdAG Where, 5M refers to the working pressure = 5000 psi 13 5/8" is the diameter of the vertical bore RSRdAG is the order of components from the bottom up     

G = rotating BOP for gas/air drilling A = annular preventer Rd = double ram-type preventer S = drilling spool R = single ram-type preventer

249

Blow out preventer equipment for coiled tubing drilling Stripper It is Pressure containment device – Primary Barrier in well control system which installed above BOP & below injector head. It is Hydraulic activated from control cabin and can be redressed during operation with pressure isolated. There are many types of CT stripper:    

Conventional Stripper Tandem Stripper Side Door Stripper Radial Stripper

 Conventional stripper: is operated hydraulically since hydraulic pressure applied through Pack Port moves Lower Bushing upward and energize stripping element against Well pressure. It can be redressed in period between 45 min to 1 hr and working over CT range from 1” - 1½”.  Side door stripper: it is mounted closer to injector head. It is also easier and safer access for Seals inspection. Side door stripper is operated hydraulically since Hydraulic pressure applied Closing Port moves Upper Bushing downward and energize stripping element. Well pressure provides gives no impact in energizing element. It can be redressed in period between 5 min to 10 min and working over CT range from 1” - 1¾”  Tandem stripper: it is used in conjunction with fixed Stripper (Back up Stripper system) and it similar in principle with Side Stripper. It allows operation to continue without delay.

FIGURE 15: STRIPPER TYPES

250

Coiled Tubing Blowout Preventer It‘s serve to provide a mean of securing the CT & isolate well pressure during Normal, Unusual or Emergency operating situations. It’s a Mechanical Closable Type of Secondary Barrier. It is Function & pressure test is compulsory before used. BOP Rams are hydraulically & mechanically activated only during CT in stationary position.

Shear & Seal BOP It‘s serve to provide a Tertiary Barrier. It is mounted directly above the Xmas Tree. Always function test the ram before executing the CT operation & the blade/cutter is only good for one-time use.

FIGURE 16: CT BOP TYPES


CT BOP available in various configurations: SINGLE, COMBI, TRIPLE COMBI & QUAD BOP

251

Coiled tubing BOP stack arrangements High pressure wells:

Low pressure wells:

FIGURE 17: CT BOP STACK ARRANGEMENTS

Well control for underbalanced drilling (UBD) Primary well control In conventional drilling, primary well control is obtained by creating a hydrostatic pressure with the mud column, which exceeds the pressure in the formation being drilled. In underbalanced drilling, the primary well control function of the mud column, has been replaced by flow and pressure control. The bottom-hole pressure and consequently the reservoir influx is monitored and controlled. Flow control is achieved by means of a closed loop surface system. The main components of the closed surface system are: • A sealing mechanism around the drill string

252

• Surface safety valve (ESD valve) • Choke manifold • Surface fluids / solids handling system

Sealing mechanism around the drill string

The passive system depends on a friction fit between the drill pipe and the rotating pack-off and well bore pressure to effect a seal. Examples of the passive system are the Weatherford-Williams RCH, Drilco Grant’s low-pressure heads and Stacy’s medium pressure heads. The active system uses hydraulic pressure to effect and maintain the seal around the drill pipe. Some examples of RCD that have been used on Shell’s operations are: 1. Rotating Control Head (RCH – Weatherford-Williams Tool Company Inc.) 2. Rotating Blowout Preventer (R-BOP – Northland Energy.) 3. Pressure Control While Drilling (PCWD – Shaffer Pressure Control) It is also worth noting that an RCD is not a diverter although it diverts flow as one of its functions. Diverters refer to a specific piece of equipment and are used in low-pressure applications only.

1. Passive system - Weatherford-Williams Rotating Control Head (RCH) The Williams RCH uses one or two stripper rubbers, which are designed typically for 0.5 inches of interference between the inside diameter of the rubber and the drill pipe. The initial seal comes from this interference fit and is supported by wellbore pressure, not by active pressure. Low-pressure leakage may occur when worn rubbers are in place.


At surface, well-bore pressures are contained by means of a sealing mechanism around the drill string. Well-bore pressure should be continuously restrained while allowing drill string rotation and pipe movement. Pipe strippers in CT drilling and a snubbing annular or a rotating control devise (RCD) in jointed pipe UBD operations provide the sealing mechanism around the pipe. There are two types of RCD systems, passive systems and active systems.

This unit is rated for 5000 psi in static (non-rotating / non-stripping) mode. The unit is rated for 2500 psi in dynamic mode (stripping and rotating). A disadvantage of the RCH is that staging large diameter tools through the stripper rubber is not possible. Therefore, the bearing assembly must be removed which eliminates the primary well control device from the system during the staging operation.

253

FIGURE 18: WEATHERFORD -WILLIAMS R OTATING CONTROL HEAD

2. Schaffer’s PCWD and Northland’s R-BOP To reiterate, RCD’s should always be used in conjunction with the conventional blowout preventer stack, even if the name implies that it is a rotating blowout preventer. These devices are used to control and divert the flow from the well in an underbalance drilling operation, secondary well control however, is still provided by the conventional stack. One of the obvious differences between these units and the RCH is the active system. RCD uses hydraulically actuated packing elements to seal around the drill pipe. The hydraulic closing pressure can be varied automatically as the well-bore pressure varies. The packing elements are able to close on open hole. When the packing element is open, these devices allow full access to the well-bore (up to a max. of 11”). The packoff elements on both devices remain closed at all times when in underbalanced drilling mode. The Shaffer PCWD Rotating BOP is rated to 5000 psi working pressure in static (non-rotating) mode. The working pressure in dynamic mode varies from 3500 psi at 50 RPM to 2000 psi while rotating up to 200 RPM. Northland’s RTI 11-3 R-BOP can handle a maximum static pressure of 2000 psi and a maximum pressure while drilling of 1500 psi. The maximum rotational speed is 100 RPM. The working pressure while stripping is 1000 psi .

254

FIGURE 19: SHAFFER PCWD R OTATING BOP

Surface safety valve

In an Underbalanced Drilling operation, the rigs kill system remains tied per normal drilling operation. If the ESD system is activated, the driller (and crew) must ensure that the rig’s HCR valve to the choke manifold remains closed since opening the HCR valve will bypass the closed in ESD valve and allow well-bore fluids to enter the UBD surface system.

FIGURE 20: ESD V ALVE L OCATION


A surface safety valve (fail close) provides an additional barrier between wellbore pressure and the surface separation equipment. A surface safety valve is usually installed between the wellhead and the choke manifold and controlled by an emergency shutdown system (ESD). The ESD system used in UBD operations is usually a combination Manual/Automatic system.

255

UBD BOP stack arrangement Wellheads used in underbalanced drilling vary from crude, very simple equipment for very low pressure operations to expensive, redundant systems designed for very high pressure operations.

Low pressure oil wells Gas, mist, and foam drilling are normally utilized on low pressure wells. For such extremely low pore pressure drilling applications, a simple annular preventer alone might suffice to contain wellbore pressures; however, a principal manufacturer of such equipment strongly cautions that such use exceeds the design criteria of this equipment. Therefore, the minimum setup for an underbalanced drilling system should consist of: 1. Rotating head 2. Two ram set of manually-operated blowout preventers, consisting of a pipe ram and a blind ram. An improvement to this basic system would be installing the rotating head above a set of hydraulically-operated blowout preventers. For slightly higher pressure operating conditions, a system consisting of 1. Rotating head 2. Annular preventer 3. A two ram set of manually operated preventers will probably work adequately. For added safety, hydraulically operated preventers with a manual backup should be provided These basic systems all use a rotating head with a 400 psi (sometimes 500 psi) MWP (Maximum Working Pressure) capability.

256

FIGURE 21: LOW PRESSURE UBD BOP STACK

High pressure gas or oil well

Blind rams should be installed in the bottom set of rams (when a two ram system is used). Sometimes a third set of rams (pipe rams) is utilized. In this case the RBOP is installed atop an annular preventer. The blind ram is placed between the two sets of pipe rams. So the arrangement would be as follow; 1. 2. 3. 4. 5.

RBOP Annular preventer variable Pipe ram blind ram Pipe ram

The lowermost set of rams should be installed directly atop the wellhead (or an adapter spool if necessary). You should never place any choke or kill lines below the lowest set of rams because if one of these lines cuts out, there is no way to shut in the well.

Care must be taken to utilize a rig with a substructure high enough so that the wellhead is not below ground level, with space enough to put the entire desired BOP stack below the rig floor.


Gasified liquids, flow drilling, mud cap drilling are utilized on high pressure wells. Rotating heads on top of conventional hydraulically operated BOP usually suffice. Nitrified liquids are often used with an RBOP installed atop a conventional BOP stack.

257

FIGURE 22: UBD BOP S TACK CONFIGURATION FOR OIL WELL

258

FIGURE 23: UBD BOP STACK CONFIGURATION FOR GAS WELL

Critical Sour gas well:

If hydrogen sulfide (H2S) gas is expected or if formations with even higher pore pressure are drilled, wellhead equipment design might call for either coiled tubing drilling (CTD) or snub drilling operations.

  

cubic meters per second (m3/s) or greater and less than 0.1 m3/s and which is located within 500 meters (m) of the boundaries of an urban center; m3/s or greater and less than 0.3 m3/s and which is located within 1.5 km of the boundaries of an urbancenter; m3/s or greater and less than 2.0 m3/s and which is located within 5 km of the boundaries of an urban center;

Snub drilling and CT drilling have BOP stacks that also allow tripping at much higher pressures than other forms of UBD (routinely up to 10,000 psi). The BOP stack arrangement will be as follow

1. 2. 3. 4.

Stripper assembly (optional) Hydraulic connector Flow spool Quod BOP stack a. Blind ram b. Shear ram c. Slip ram d. Pipe ram 5. Annular BOP 6. Seal pipe ram 7. Riser pipe 8. kill spool 9. shear/blind ram 10. slip/pipe ram 11. kill spool 12. Xmass tree


Critical sour well is any gas well from which the maximum potential H2S release rate is greater than:

259

FIGURE 24: UBD BOP STACK CONFIGURATION FOR CRITICAL SOUR GAS WELL

BOP schematic of obaiyed D-2

FIGURE 25:BOP SCHEMATIC

260

OF OBAIYED

D-2

References

Rehm B and McClendon R (1971) "Measurement of formation pressures from drilling data" SPE 3601, AIME Annual Fall Meeting, New Orleans.

Snyder, R. and Suman G (1978, 1979) "World Oil's Handbook of High Pressure Well Completions World Oil".

Schlumberger (1972). "Log Interpretation Principles". Vol 1. Schlumberger Publication.


Exlog Applications Manual (various prints) "Theory and evaluation of formation Pressures" Exploration Logging Inc.

261

WELL COMPLETION FOR UNDERBALANCED DRILLING

262 Well completion in underbalanced drilling

Well Completion Wells are one of the main investment items in the development of a field and must be completed setting the goal of maximum production rates obtainment Well Completion is a very important activity in the upstream part of the hydrocarbon exploitation which interfaces the reservoir with the ‘Topside Facilities’ to the ‘Production Network’. The completion design is a part of the well design and sequentially follows the drilling engineering side of it.

Contents

Well completion in underbalanced drilling

In Underbalanced Drilling operation

1- Completion objective and functions 2- Vertical well completion 3- Horizontal well Completion 4- UBD completion 5- Obaiyed – D2-c/d 263 Completion

Completion objective and functions. The fundamental objectives for a completion are:  Achieve the optimum production or injection rates at the lowest capital and operating costs.  Be as simple as possible to increase reliability.


 Provide adequate safety in accordance with legislative or company requirements and industry common practices.

264



Be as flexible as possible for future operational changes in well function.

The main function of a completion is to produce hydrocarbons to surface or deliver injection fluids to formations. This is its primary function; however a completion must also satisfy a great many other These main functional requirements must be built into the conceptual design and include:  Protecting the production casing from formation pressure.  Protecting the casing from corrosion attack by well fluids.  Preventing hydrocarbon escape if there is a surface leak.  Inhibiting scale or corrosion.  Producing single or multiple zones.

Completion Types There are several ways of classifying or categorizing completion types. The most common criteria for the classification of completions include the following:  Wellbore/reservoir interface, i.e., open-hole or cased hole, horizontal completion  Producing zones, i.e., single zone or multiple zone production  Production method, i.e., natural flowing or artificially induced production

There are three reservoir-wellbore interface options which can be further classified into seven major alternatives in completion architecture.


RESERVOIR-WELLBORE INTERFACE

265

1. Vertical or highly deviated well Completion Well completion in underbalanced drilling

1.1Open Hole Completions Their use is predominately in thick carbonate or hard sandstone reservoirs that produce from fracture systems or thin permeable streaks which are difficult to identify on logs and are easily damaged by drilling and cementing operations. They maximize the fracture intersections and inflow potential due to the large surface area if drilling and completion damage is avoided. However they provide little or no selectivity in reservoir management to reduce unwanted water or gas production. An open hole completions can subsequently be converted to a liner completion to overcome the selectivity problem.

1.2Uncemented Liner Completions Uncemented liners are used to overcome production problems associated with open hole completions and to extend their application to other types of formations. The formation is supported by a either a slotted liner, sand screen or is gravel packed.

First: Slotted Liner 



This type of completion entails a liner with flow slots machined throughout its length installed below the production casing. The slot widths can range between 0.254 - 1.016mm. A slotted liner is used where there is a risk of wellbore instability to maintain a bore through the formation which otherwise might collapse and plug off all production. It also helps in liquid lift due to the smaller flow area.

266 FIGURE 1 S LOTTED LINER

Second: Wire Wrapped Screen

FIGURE 4: WIRE WRAPPED S CREEN

Third: External Gravel pack An open hole gravel pack is used where the sands are too fine or abrasive for screen. The open hole is under-reamed to remove drilling damage and to create annulus for the filter sized gravel to pack against the formation wall. When installed, it is the most effective sand control measure for weak sandstones unconsolidated rocks, however carries more risk than a cased hole gravel pack.


A plain wire wrapped screen is used either as a simple filter to strain out small amounts intermittently produced sand from a relatively stable formation or as a sand retention where high permeability, coarse sands would readily flow onto the screen forming zone.

FIGURE 5: E XTERNAL GRAVEL PACK

267

1.3 Perforated Completions


This type of completions are the most common world-wide due to the selectivity, flexibility, lower costs, increased safety and convenience that they provide. There are three subdivisions, standard, fracture stimulation and cased hole gravel pack The key issues in cased hole completion design are:  Perforated interval selection, gun type, shot density, underbalanced or Overbalance and perforating method, i.e. casing guns, through tubing guns or TCP.  Completion fluids program selection with regard to fluid quality and formation damage.  Type of formation and if special perforating techniques are required, e.g. high shot density, ultra deep penetration or stimulation treatments. 

Effective zonal isolation due to cement quality and distance between zones .

1.4Standard Perforated Casing Completions These are used when the rock is reasonably stable and permeable. Deep penetrating perforating charges are generally used especially in hard rock, with the shot density dependent upon the vertical permeability and layer frequency, the deliverability requirements and method of perforating. The deep penetrating charges are desired to perforate through the damage zone cause by the drilling or completing process. Perforating underbalance may also improve perforation clean-up.

Horizontal well Completion 1.5Open hole Open-hole completion is inexpensive But is limited to competent rock formation. Additionally, it is difficult to stimulate open – hole Wells and control either injection or production Along the well length.

268

FIGURE 9:: OPEN HOLE COMPLETION FOR HORIZONTAL WELL

1.6Slotted liner completion The main purpose of inserting a slotted liner in a horizontal well is to guard against hole collapse. Additionally, a liner provides a convenient path to insert various tools such as coiled Tubing in horizontal well. Three types of liner have been used: a. Perforated liners, where holes are drilled in the liner.

FIGURE 10 SLOTTED LINER

1.7Liner with partial isolation: Recently external Casing Packers (ECPS) have been installed outside The slotted liner to divide a long horizontal wellbore Into several small sections (as shown in figure). This Method provides limited zone isolation, which can Be used for stimulation or production control along The well length.


b. slotted liner, where slots of various width and depth Are milled along the liner length.

269

FIGURE 11 PARTIAL CASING ISOLATION

1.8Cemented and perforated liner:


It is possible to Cement and perforate medium and long radius wells. At the present time it is not economically possible to Cement short radius Wells. Cement using horizontal Well completion should have significantly less free Water content than that used for vertical well Cementing. This is because in a horizontal will, due to Gravity, free Water segregates near the top portion of The well and heavier cement settles at the bottom. This Results in a poor cement job.

270

FIGURE 12 CEMENTED & PERFORATED LINER

UB Completion One of the primary advantages of drilling wells underbalanced is the elimination or minimization of formation impairment. In overbalanced situations, drilling fluid and Solids can penetrate and damage matrix porosity or fractures, reducing the permeability. If a well is properly drilled under underbalanced Conditions, but is completed using over balanced methods, much if not all of the impairment-reducing benefits might be permanently lost. Even if this completion-related damage can be removed or bypassed, the associated expenses can be avoided if the operator uses proper underbalanced completion procedures. These procedures, sometimes called “live well,’’ underbalanced completion techniques, are described in this section. They include:    

Running production casing, liners, slotted liners and other tools underbalanced, Controlled cementing of production casing or liners, Running production Tubing and down hole completion assemblies, and, Perforating underbalanced

Running Casing and Liners Underbalanced Before drilling operations are completed, and the bottom hole assembly (BHA) is removed from the wellbore under pressure, completion protocol must be determined. For example, will the completion be barefoot (open hole) or will some type of casing or liner be run.

To run production casing or an un slotted production liner in a live well, a float shoe and float collar are usually used. The shoe and float collar are often separated by two joints of pipe, in order to isolate contaminated cement and to prevent it from surrounding the lower portion of casing in the open hole. Depending on the surface pressures, it may be necessary to flow the well through the choke manifold while running pipe, to reduce the shut-in surface pressure. Even flowing the well might not sufficiently reduce this pressure to permit passage of the pipe into the well against underbalanced forces. If this is the case, a snubbing unit or a coiled tubing injector head might be required to push the casing until it becomes “pipe heavy.” On the other hand, a slotted liner does not restrict the flow of fluids into the liner (through the slots). The slotted liner and liner hanger are run on the bottom of drill pipe or some other work string. A drill float is generally run above an on/off tool, located immediately above the liner hanger. Once the hanger is set, the on/off tool is released and the drill pipe or work string is tripped out of the hole. The drill float provides back flow protection. It may be necessary to “flood” the backside with drilling fluid to reduce the surface Pressure and enable tools or pipe to be run into the hole. Fluid is continuously pumped down the annulus to overcome pressure resistance. If necessary, the rubber element or packer, inside a rotating head or RBOP, can be removed to allow larger diameter pipe to be run through the wellhead stack.


If the completion is not barefoot, it becomes necessary to run the casing or liner without Killing the well. In this scenario, surface pressures are usually increased to subdue exposed down hole Formations, without exceeding their pore pressures. This is done by replacing the lighter annular fluid by bull heading a heavier fluid down the back Side before tripping out of the hole.

271

Cementing Pipe Under pressured Presuming that casing has been run underbalanced, underbalanced cementing should also be considered. Formation impairment from the cement and associated filtrate fluids can be equally or more damaging than drilling. Underbalanced cementing is not substantially different from underbalanced drilling. The hydrostatic head of the slurry can be reduced by entraining gas, usually nitrogen, or reduced density additives. These technologies were originally developed to avoid breakdown in weak formations.


Running Tubing in Underbalanced Wells

272

Whether or not a well is designed as an open hole completion, a slotted liner completion or a perforated casing completion, production tubing is generally required to protect production casing against excessive or concentrated pressures and to minimize corrosion and/or erosion. Most regulatory agencies enforce the use of tubing in well completions, to protect shallow freshwater aquifers against hydrocarbon or salt invasion and pollution. If the underbalanced well above is an open hole or slotted liner (completion, there will generally be pressure at the surface. Cemented casing completions will have zero pressure until they are perforated. Methods have been developed to run completion assemblies and tubing downhole under pressured, in open hole and slotted liner wells. Un perforated, cased wells present no problem and tubing is run into the well without special equipment. If a well has surface pressure, it should preferably not be Killed (formation impairment from cornpletion fluids and solids might occur). Since it is not possible to use permanent tubing string floats similar to drill floats, temporary float systems have been developed. By placing a tubing sub, containing a custom glass disk in the string, pipe and tools can be run in the well under pressure without backflow of wellbore fluids. The glass or other similar material isolates the inside of the tubing from pressure while it is run in the well along with a retrievable packer or seal bore assembly for a permanent packer installation. Once the packer is set and the system pressure tested, this glass disk is broken by dropping a sinker bar down the tubing and breaking the disk. A “catcher” assembly is usually positioned inside a mud anchor, located below a perforated nipple underneath the packer, to keep the sinker bar from falling out of the tubing g into the casing. This is a simple and effective technique.

There are other methods to isolate surface pressure and trip into a well. For example, a wire line-set permanent packer can be run with a pump-out or push-out plug assembly. Once the packer is run and set in place, pressure above the packer can be bled off to zero to run the tubing.

Another method to protect against surface pressure while running tubing into the well Involves the use of a pressure rupture disk located inside the tubing string. Again, after setting and hydrostatic testing of the packer, this pressure disk is ruptured by pressuring up the tubing to a preset limit. Of all of these methods, the most commonly used is the shear glass disk sub because of its reliability and simplicity.

Completing Underbalanced Drilled Wells The majority of early wells drilled underbalanced could not be completed underbalanced. The majority of the early UBD wells were displaced to an overbalanced kill fluid prior to running the liner or completion. Depending on the completion fluid type, some formation damage would take place. The damage may not have been as severe for completion brine as it might have been with drilling mud, but significant reductions in productivity of underbalanced drilled wells have been encountered after the installation of the completion. If the purpose of underbalanced drilling is for reservoir improvement, it is important that the reservoir is never exposed to overbalanced pressure with a non-reservoir fluid. If the well has been drilled underbalanced for drilling problems, and productivity is not impaired, then the well could possibly be killed and a conventional completion approach can be taken.


Alter the tubing is stung into the packer and pressure tested, either pump pressure or a sinker bar is used to "open" the well to the surface; communicating the formation below the packer with the surface through the production tubing.

A number of completion methods are available for underbalanced drilled wells: • • • •

Liner and perforation Slotted liner Sand screens Barefoot (open hole)

All of the above options can be deployed in underbalanced drilled wells. The use of cemented liners in an underbalanced drilled well is not recommended if the gains in reservoir productivity are to be maintained. It is generally not possible to cement a liner in an underbalanced mode, although the use of foamed cements may provide some solutions in certain circumstances. The completion

273

requirements for a UBD well must be reviewed and analyzed as part of the feasibility study prior to commencing an underbalanced operation Irrespective of the completion lining required for the reservoir, the installation process for a completion will have to be carefully reviewed during the planning process to ensure that underbalanced status is maintained during the completion installation.


If a packer type completion is installed. The production packer and tailpipe are run and set on drill pipe with an isolation plug installed in the tailpipe. If the well is maintained underbalanced, well pressure will normally require the production packer and tailpipe to be snubbed into the well against well pressure. If a liner top completion is used in a monobore well drilled underbalanced, the use of a float collar may have to be considered to maintain well control.

FIGURE 2: UBD COMPLETION TYPES

274

Obaiyed – D2-c/d Completion Running completion

1. Install THS and N/U BOP and test both to 5,000 psi. 2. Retrieve RTTS packer. 3. R/U for running 5” completion string with the redressed KC-22 S anchor seal assembly and 4” AF nipple, SC-SSSV. 4. RIH with completion string as per program and pressure test 5” tubing as per completion program. 5. Make up the SC-SSSV, connect the control to the safety valve, open the flapper and start RIH with tubing to surface as per sketch. 6. Sting into the Premier packer seal head with the KC-22S anchor seal assembly, space out the completion string to land in the tubing hanger. Set down 10,000 lbs. 7. Pooh and install pup joints as required, re-sting in the packer head and latch the KC-22S anchor seal assembly in the head, pull test the anchor seal assembly by 10 klbs. 8. Set tubing hanger, with 10,000 lbs. compression, in place and tie down connect control line. 9. Install BPV in tubing hanger. 10. N/D BOP


Steps:

275

Installing wellhead A 5K FMC wellhead (Bapetco standard) will be installed. Follow FMC detailed procedure for installing, function and pressure testing the X-mas tree. An FMC representative will need to be available at the well site.

Bringing the well on-line


Outline procedure (detailed procedures will be provided by the user-departments)

276

Steps: 1) Hook-up production flow lines and control panel and test same 2) Rig up coiled tubing on the wellhead and lift the column of kill fluid from the well using nitrogen 3) Record fluid returns in order to calculate the potential differential pressure across the WL plugs 4) Rig up slick line and recover the top and bottom No-Go plugs 5) Rig up well test package for short well test 6) Bring well on production and monitor flow rates 7) Shut-in well for build up 8) Rig down all equipment and bring well on stream to OBA production facilities


Completion equipment list

277

Thread

Weight / Material

OD/ID (in)


Item description

278

Tubing

5” New VAM Box x Pin

15 ppf / S13Cr

5.0 / 4.4

Flow coupling


15 ppf / S13Cr (819-24)

5.563/4.276

TR-Safety valve


Incoloy 825

5.5 / 4.125

Flow coupling


15 ppf / S13Cr (819-24)

5.563/4.276

Tubing


15 ppf / S13Cr

5.0 / 4.4

AF no-go nipple


S13Cr

5.0 / 4.0

Tubing


15 ppf / S13Cr

5.0 / 4.4

K-22 Anchor seal


S13Cr (443-38)

5.0 / 4.2

Packer head

4.5” New VAM Box x Pin

13.5 ppf / S13Cr

5.8 / 3.9

Spacer Joint

4.5” New VAM Box x Pin (LH)

13.5 ppf / S13Cr

4.5 / 3.9

Premier Production Packer

4.5” Box x 5” Pin New VAM

29-32 ppf / S13Cr

7.0 / 3.9

Pup Joint

5” VAM Box x Pin

15 ppf / S13Cr

5.0 / 4.4

Crossover Sub

5” Box x 4.5” Pin New VAM

S13Cr

3.958

F-top No-Go Nipple

4.5” VAM Box x Pin

S13Cr

4.5 / 3.81

Tubing


13.5 ppf / S13Cr

4.5 / 3.9

R-bottom No-Go Nipple


S13Cr

4.5 / 3.81

Seal Assembly SI/SO

4.5” New VAM Box

12.6 ppf / S13Cr

3.958

Wellhead configuration items and stress check

THA 11” x 5” VAM

THS 11” 10Ksi x 11” 5Ksi Internal Latch

DDV – Wellhead penetration spool 11” 10Ksi – modified CHS


Tree 11” x 5 1/8” 5Ksi

279 Casing Head Spool 13 5/8” 5ksi x 11” 10ksi Weatherford DDV procedures Mandrel Hanger 11”operating x 7”

Note: another valve will be installed behind the existing one. Reference is made to WFT document: DDV OM 001 – Rev F, V03-26-05, for all DDV operations.

References Snyder, R. and Suman G (1978, 1979) "World Oil's Handbook of High Pressure Well Completions World Oil".

Schlumberger (1972). "Log Interpretation Principles". Vol 1. Schlumberger Publication.


Fertl W.H. (1976) "Abnormal Formation Pressures". Elsevier, Amsterdam.

280

280

This chapter outlines the steps and methods used to plan a successful aerated fluids drilling operation. This chapter also illustrates the application of these steps and methods to typical deep drilling operations. The objective of these steps and methods is to allow engineers and scientists to cost effectively plan their drilling operations and ultimately select their drilling rig, compressor, and other auxiliary air and gas equipment. The additional benefit of this planning process is that the data created by the process can be later used to control the drilling operations as the actual operations progress.

Contents 1- Minimum volumetric flow rate theory 2- Injection pressure calculation approximation models 3- Injection pressure calculation With major and minor losses 4- compressor selection

281

Introduction Aerated drilling operations use a variety of incompressible fluids and compressed gases to develop a gasified drilling fluid. The majority of the operations use standard fresh water based drilling mud with injected compressed nitrogen. More recently inert atmosphere has been used as the injected gas to reduce the corrosion of the drill string and the borehole casing. In this chapter a standard drilling mud and nitrogen will be used as the example aerated drilling fluid. The basic direct circulation drilling program goes through two models:  The minimum volumetric flow rate model  The injection pressure calculation model

Minimum Volumetric Flow Rates Most aerated drilling operations are planned with a constant volumetric flow rate of incompressible drilling fluid and only the volumetric flow rate of the compressed gas is allowed to vary. The volumetric flow rate of gas is usually increased as the depth is increased in order to maintain the same aerated fluid properties in the annulus column. The drill pipe injection technique requires that both the incompressible drilling fluid injection and the compressible gas injection be suspended when connections and trips are made. Similarly, the annulus injection technique requires that the incompressible drilling fluid injection be suspended when connections and trips are made. Further, the cleaning, lifting, and suspension capabilities of the incompressible drilling mud is in general independent of the depth of drilling. Conversely, the cleaning and lifting capabilities of compressed gas are dependent of the depth of drilling. Also, it must be noted that compressed gas drilling fluids have little or no suspension capabilities. Therefore, when designing an aerated drilling fluid, the injected compressed gas should not be assumed to contribute to bottomhole cleaning, lifting, and suspension of rock cuttings in the annulus. The additional cleaning and lifting properties of the compressed gas to the aerated drilling fluid should be considered as a bonus. This argument requires that the incompressible drilling fluid properties and circulation characteristics be designed to provide the aerated drilling operations with stand-alone cleaning, lifting, and suspension capabilities of the rock cuttings in the annulus.

282

The critical concentration velocity is the additional velocity needed to distribute the rock cuttings through the incompressible drilling fluid at a predetermined concentration factor. The usual concentration factor is 0.04. Therefore, the critical concentration velocity, Vc, is

Vc 

k 3600  C

Where, 

K is the drilling rate of penetration (ft/hr, or m/hr)



C is the concentration factor (usually assumed to be 0.04)

The drilling cuttings particle average diameter can be estimated using the following expression:

Dc 

k (60) N

Where, 

Dc is the average diameter of drill bit cuttings (ft, or m)



N is the average drill bit rotary speed (rpm(

Terminal Velocities For direct circulation operations the terminal velocity of the rock cutting particle is assessed in the annulus section of the borehole where the cross-sectional area is the largest. The terminal velocity will depend on the actual flow conditions in the annulus section (i.e., whether the flow is laminar, transitional, or turbulent). The fluid flow regions are classified as Laminar, transitional, or turbulent. These flow regions can be approximately defined using the non-dimensional Reynolds Number. The Reynolds Number is

NR 

DV



where D is the diameter of the flow channel (ft, or m). V is the velocity of the flow (ft/sec, or m/sec) ѵ is the kinematic viscosity of the flowing fluid (ft 2/sec, or m2/sec)

283

The generally used empirically derived terminal velocity expressions in English Units are given below. For the laminar region, the expression is

s  f Vt1  0.0333Dc2   e

  

0
For the transition region, the expression is

 ( s   f ) 2 / 3   Vt 2  0.492 Dc   (   )1 / 3  e  f 

0
For the turbulent region, the expression is

Vt 2

 s   5.35 Dc    f  

f

   

1/ 2

NR>4000

Where, 

Vt1, Vt2, Vt3 are terminal velocities (ft/sec).



s f



μe is the effective absolute viscosity (lb-sec/ft2).



is the specific weight of the solids (lb/ft 3). is the specific weight of the fluid (lb/ft 3).

Obayed Minimum volumetric flow rate study

284



D/P 14987 ft, OD2.375, ID1.185, N.W.=6.65lb/ft



D/C 330 ft, OD3.125, ID1.5, N.W.=20 lb/ft



Hole=3.875 in



The drilling is to be carried out at a surface location of 67 ft above sea level where the actual atmospheric temperature is 60˚F.



The regional geothermal gradient is approximately 1.54 ˚F/100 ft



The drilling mud is to have a specific weight of 10.05 lb/gal drilling



Mud with a plastic viscosity of 30 cps and a plastic yield stress of 5 lb/100 ft2.



Drill pipe injection technique will be used and the drilling operation will be carried out to maintain a Bottomhole pressure of 5900 psia while drilling the interval from the 13727 ft to 14360 ft (md).



Average rate of penetration=3.12 m/hr=10.23 ft/hr=0.00284 ft/sec

The critical concentration velocity is Vc 

k 10.23 =0.071 ft/sec  3600  C 3600  0.04

The specific weight of the sedimentary rock (Safa sandstone) to be drilled is approximately

 s  2.65( gm / cc)  62.4 =165.36 lb/ft3 The specific weight of the 10 lb/gal drilling mud in consistent units is

 f  10.5( ppg )  7.48 =78.54 lb/ft3 The absolute plastic viscosity of the drilling mud in consistent units is

 e  300.0010.02089 =0.0006267 lb.sec/ft2 The approximate average diameter of the rock cuttings particle in consistent units is Dc=0.198/12=0.0165 ft Assume the flow is laminar The terminal velocity for laminar flow conditions

s  f Vt1  0.0333Dc2   e

 165.36  78.54    0.0333  0.0165 2   =1.256 ft/sec  0.0006267  

The total velocity of the fluid is V f  Vt  VC =0.071+1.256=1.33 ft/sec

The above total velocity of the fluid must be the minimum average velocity of the incompressible fluid in the borehole annulus section where the cross-sectional area is the largest. The largest cross-sectional area of the annulus is in the cased section of the well where the inside diameter of the casing is 4.09 inch and the outside of the diameter of the drill pipe is 3.875 inch.

285

Thus, this annulus cross-sectional area, Aa, is

Aa 

  6.184 2  3.875 2   4 

  0.1266 ft2 

144

The volumetric flow rate in the above annulus section is Qa  Aa  V f  0.1266  1.33 =0.168 ft3/sec=0.168*7.48*60=75.8 gal/min

The hydraulic diameter for this annulus cross-section, is Dhy 

(6.184  3.875) =0.192 ft 12

The drilling mud density

m 

f g



78.54 =2.439 lb.sec2/ft4 32.2

The general equation for kinematic viscosity



 e 0.0006267 =0.0002569 ft2/sec  m 2.439

Reynolds number for the volumetric flow rate derived from the laminar flow terminal velocity equation. NR 

DV





0.192  1.33 =994 0.0002569

Assume the flow is turbulent The terminal velocity for turbulent flow conditions

 s  f Vt 2  2.95 Dc    f  

   

1/ 2

  165.36  78.54    5.35 0.0165   78.54   

1/ 2

=0.78 ft/sec

The total velocity of the fluid is V f  Vt  VC =0.071+0.78=0.9 ft/sec

The volumetric flow rate in the above annulus section is Qa  Aa  V f  0.1266  0.9 =0.114 ft3/sec=0.168*7.48*60=51.14 gal/min

286

For turbulent flow conditions, the effective absolute viscosity of a drilling mud with a plastic viscosity must to be modified before it is used in the Reynolds number equation

t 

e 3.2



0.0006267 =0.000196 lb.ft/sec2 3.2

The effective kinematic viscosity for the drilling mud with plastic properties is



 t 0.000196 =0.000080 ft2/sec  m 2.439

Reynolds number for the volumetric flow rate derived from the turbulent flow terminal velocity equation. NR 

DV





0.192  0.9 =2160 0.000080

The Reynolds number above is greater than 2,000. This indicates that the volumetric flow rate of 51.14 gal/min produces turbulent flow conditions in the largest cross-section of the annulus.

The turbulent flow analysis result is inconsistent with the result of the laminar flow analysis. Also, since the turbulent flow analysis indicates turbulent flow conditions exist at a lower volumetric flow rate than the laminar flow analysis, then the laminar flow analysis is considered valid and the turbulent flow analysis invalid

Therefore, the minimum volumetric flow rate of the incompressible drilling fluid (the drilling mud) is assumed to be approximately 76 gpm (says 80 gpm)

287

Injection Pressure and Selection of Compressor Equipment The analyses of aerated fluid vertical drilling problems have been carried out by two distinct analytic methodologies.

1. Non-Friction Approximation The simple non-friction methodology allows straight forward deterministic approximate solutions of aerated drilling problems. However, the practical applicability of these non-friction solutions is limited to shallow (generally less than 3,000 ft of depth) wells with simple geometric profiles

Obayed non-friction approximation model calculation An average atmospheric pressure of 12.685 psia for a surface location of 4000 ft above sea level Pat=12.685 psia=1826.6 lb/ft2 abs The actual atmospheric temperature of the air at the drilling location Tat=60 oF=60+459.57=519.67 oR Thus, Pg and Tg become Pg=Pat=1872 lb/ft2 abs Tg=Tat=519.67 oR The temperature of the rock formations near the surface (geothermal surface temperature) is estimated to be the approximate average year round temperature at that location on the earth’s surface. It gives 535˚R for average year round temperature for a surface elevation location of 4,000 ft above sea level. Therefore, the absolute temperature of the rock formations at the surface, Tr, is

Tbh  Ts  G  H =535+0.0154*14370=756˚R The borehole average temperature, Tav, is

Tav 

288

Tbh  Ts =645˚R 2

The bottomhole pressure, Pbh Pbh=5900*144=849600 lb/ft2 abs

the specific weight of the gas entering the compressor is

g 

Pg  S R  Tg

S=0.05*32+0.95*28/28.97=0.973

g 

Pg  S R  Tg



1872  0.973 =0.0656 53.36  519.67

The volumetric flow rate of drilling mud, Qm, in consistent units is Qm 

80 =0.178 ft3/sec 7.48  60

The weight rate of flow of the drilling mud is .

w m   m  Qm  78.54  0.178 =13.98 lb/sec

The openhole diameter, Dh, is Dh=3.875 inc=3.875/12=0.323 ft Weight rate of flow of solids from the advance of the drill bit is .

ws 

 4



Dh2 w S s k 

4

 0.3232  62.4  2.65 

10.23 =0.0385 lb/sec 3600

The gas volumetric flow rate 

( w  wm ) H  Qm Pbh  Pe  Qg  s T   P  Pg  av  ln  bh    g H T   g   Pe  

(0.0385  13.98)  14370  0.168849600  1826.6 =4.54ft3/sec=4.54*60=273 scfm Qg   645   849600  1826.6  ln    0.0656  14370  519.67   1826.6 

The volumetric flow rate of compressed air determined above which is rounded up to 300 scfm is the flow rate to be injected into the incompressible fluid volumetric flow rate of 80 gal/min. This gas flow rate has been determined with the non-friction method.

289

2. Major and Minor Losses and Injection Pressure Surface Return Flow Line

Obayed Major and minor losses approach Assume Qg=19.47 ft3/sec An average atmospheric pressure of 12.685 psia for a surface location of 4000 ft above sea level Pat=14.685 psia=1872 lb/ft2 abs The actual atmospheric temperature of the air at the drilling location Tat=60 oF=60+459.57=519.67 oR Thus, Pg and Tg become Pg=Pat=1872 lb/ft2 abs Tg=Tat=519.67 oR The specific weight of the gas entering the compressor is

g 

Pg  S R  Tg

S=0.05*32+0.95*28/28.97=0.973

g 

Pg  S R  Tg



1872  0.973 =0.0656 53.36  519.67

The weight rate of flow of the nitrogen, .

w g  Qg   g  19.47  0.0656 =1.28 lb/sec The volumetric flow rate of drilling mud, Qm, in consistent units is Qm 

80 =0.178 ft3/sec 7.48  60

The weight rate of flow of the drilling mud is .

w m   m  Qm  78.54  0.178 =13.98 lb/sec

The openhole diameter, Dh, is

290

Dh=3.875 inc=3.875/12=0.323 ft Weight rate of flow of solids from the advance of the drill bit is

.

ws 

 4



Dh2 w S s k 

4

 0.3232  62.4  2.65 

10.23 =0.0385 lb/sec 3600

The total weight rate of flow in the annulus is . .

.

.

wt  wg  wm  ws =1.28+13.98+0.0385=15.29 lb/sec

The absolute viscosity of the drilling mud, µe=0.0006267 lb.sec/ft2 The drilling mud density

m 

f g



78.54 =2.439 lb.sec2/ft4 32.2

The general equation for kinematic viscosity



 e 0.0006267 =0.0002569 ft2/sec  m 2.439

The inside diameter of the surface return flow line, Dsr , is Dsr=5.625 inches=5.625/12=0.469 ft The length of the surface return flow line, Lsr , is Lsr =100 ft The absolute viscosity of the gas (Nitrogen) at atmospheric conditions µg=0.012 cps=0.012*0.001*0.02089=0.000000251 the density of the gas

g 

0.0741 =0.0023 lb.sec2/ft4 32.2

the kinematic viscosity of the gas



 g 0.000000251  =0.000109 ft2/sec g 0.0023

The kinematic viscosity of the aerated drilling fluid (the mixture of the drilling mud and the compressed air) can be approximated with an average kinematic viscosity term. This average kinematic viscosity term can be approximated by weight averaging the separate viscosities with the weight rates of flow of the separate fluids. .

 sr 

.

wg  g  wm  m .

.

wg  wm



1.28  0.000109  13.98  0.0002569 =0.000244 ft2/sec 1.28  13.98

291

The average velocity of the aerated drilling fluid (the mixture of the drilling mud and the compressed air) as the mixture exits the end of the surface return flow line into the atmosphere, Vsr

Vsr 

Qm  Q g

 4



0.178  19.47



D sr2

4

=113.73 ft/sec

 0.469 2

Thus, the Reynolds number of the aerated drilling fluid as it exits the surface return flow line, NRsr, is N Rsr 

Vsr  Dsr

 sr



113.73  0.469 =219507.49 0.000244

The Reynolds number calculation above is greater than 4,000. This indicates that the flow condition is turbulent. Therefore, the empirical von Karman equation must be used to determine the Fanning friction factor for the aerated fluid flow inside the return flow line.

The surface roughness of the inside of the steel surface return flow line is the absolute surface roughness of commercial steel pipe, ep ep=0.00015 ft The Fanning friction factor, fsr , for flow inside the return flow line is 2

2

        1 1     =0.015 f      Dsr   0.469     2 log 10  e   1.14   2 log 10  0.00015   1.14        For the surface return flow line increment can be solved for the pressure at the entrance end of the line, Psr . This involves selecting this upper limit of the left side intergal by a trial and error procedure. The magnitude of the upper limit pressure on the left side of the equation is selected to allow the left side integral to equal the right side integral.

292

l

100

0

0

Since the right side=  dl 

 dl =100 ft

Assume, Psr= 16.53 psia= 18.91/144=2381 lb/ft2 abs

Pen

l

dP P Bs ( P)  0 dl ex

   Bs ( P )     Pg   P 

       f wt    2 gD  Tav  sr Q g  Qm         Tg   

2381



1826.6

  Pg    P    

  Q g  Qm       2  Dsr 4  

 Tr    Tg

dP 2      45260         P   0.178   15.29     0.000497     45260 0.1726          P   0.178           

2

      

 100

The integration can be carried out on the computer using one of the commercial analytic software programs (e.g., Mathcad). The aerated drilling fluid flows from the top of the annulus into the entrance of the surface return flow line. The friction flow loss of the turn and of the two valves at the entrance of the surface return flow line must be included. The approximate specific weight of the aerated drilling fluid just after it passes through the Tee and the valves at the top of the annulus is determined using the above determined P sr .

 tee 

wt Pg Psr

 tee 



Tr  Q g  Qm Tg

15.29 =0.983 lb/ft=7.4 ppg 1826.6 535   19.47  0.178 2381 519.67

293

The approximate velocity of the aerated fluid flow just downstream of the Tee and valves is Pg Vtee 

Vtee

Psr



Tr  Q g  Qm Tg

 / 4 Dsr2

1826.6 535   19.47  0.178 2381 519 . 67 =90 ft/sec   / 4  0.469 2

The approximate pressure change, ΔPTee , through the two valves and Tee is

 Vtee2    Ptee   tee  K tee   2 K v   2 g   Where, 

KTee is the minor loss flow resistance coefficient for the Tee,



Kv is the minor loss flow resistance coefficient for a valve.

Using the dimensions of the Tee, to obtain the approximate minor loss resistance coefficient of the Tee. This is assumed as KTee= 27 The approximate minor loss resistance coefficient for the valve is Kv= 0 2 By Substituting

 90 2   =3348.85 lb/ft2 Ptee  0.983  27   2  0.2  2  32 . 2  

The pressure upstream of the Tee at the top of the annulus, P Tee

Ptee  Psr  Ptee =2381+3348.85=5729.85 lb/ft2=5729.85/144=39.8 psia

294

GEOMETRY IN THE ANNULUS Major and minor friction losses must be included in order to obtain accurate bottomhole and injection pressures. Therefore, it is necessary to include the geometric dimensions of the drill pipe tool joints. For the calculations that follow, the drill pipe tool joint lengths will be “lumped” together as a continuous length to approximate their contribution to the overall major (wall friction) loss in the flow system. DS specification 

D/P 9184 ft (do not exceeds 3400 m), OD 3.5 , ID 2.6, N.W.=14.63lb/ft



Approximately every 30 ft there are tool joints which are about 1.5 ft in length. The outside diameter of these tool joints (XT-M39) is 4.66 inches with an inside diameter of 3.4 inches



D/P 5803 ft, OD2.375, ID1.185, N.W.=6.65lb/ft



D/C 330 ft, OD3.125, ID1.5, N.W.=20 lb/ft



The outside diameter of these tool joints (WT-23) is 3.125 inches with an inside diameter of 1.5 inches

These lumped approximations for the drill pipe tool joints are somewhat rough approximations, but will give quite accurate bottomhole and injection pressures.

Using this lumped approximation, the pressure terms along the annulus around the drill pipe and inside the drill pipe are in error by a few percent. However, this shortcoming can obviously be relieved by calculating a short 1 1/2 ft long tool joint every 30 ft along the entire drill pipe length of the drill string. This can easily be accomplished with a sophisticated computer program. But these lumped approximations are very useful in demonstrating the calculation technique steps.

These lumped approximations are very easy to incorporate in an engineering calculation program and it has been found that these approximations are quite adequate for most engineering practice applications.

295

FIGURE 1: OBAYED WELL SKETCH

The calculation sequence for this illustrative example is divided into seven depth increments. The increments start at the top of the borehole with the first increment at the top and the seventh increment at the bottom. The first cased section from the surface to 11175 ft CSG dimensions OD/ID= 7''/6.184'' The total length of the lumped drill pipe body increment (first), H1, in the cased section of the borehole is H1=11175-1.5*11175/30=10616 ft The inside diameter of the casing along this length of the cased section of the borehole is D1=6.184/12=0.515 ft And the outside diameter of the drill pipes body along this length is

296

D2=3.5/12=0.292 ft

The total length of the lumped drill pipe tool joints increment (second), H2, in the cased section of the borehole is H2=1.5*11175/30=558.75 ft The inside diameter of the casing along this length of the cased section of the borehole is D1=0.515 And the outside diameter of the drill pipe tool joints along this length is D3=4.66/12=0.388 ft The total length of the lumped drill pipe body increment (third), H3, in the cased section of the borehole is H3=2506-1.5*2506/30=2381 ft The inside diameter of the casing along this length of the cased section of the borehole is D4=4.09/12=0.341 ft And the outside diameter of the drill pipes body along this length is D2=0.198 ft The total length of the lumped drill pipe tool joints increment (fourth), H4, in the cased section of the borehole is H4=1.5*2506/30=126 ft The inside diameter of the casing along this length of the cased section of the borehole is D4=0.341 ft And the outside diameter of the drill pipe tool joints along this length is D3=3.125/12=0.26 ft The total length of the lumped drill pipe body increment (fifth), H5, in the openhole section of the borehole is H5=1307-1.5*1307/30=1242 ft The inside diameter of the openhole along this length of the openhole section of the borehole is Dh=3.875/12=0.323 ft And the outside diameter of the drill pipe body along this length is D2=0.198 ft

297

The total length of the lumped drill pipe tool joints increment (sixth), H6, in the openhole section of the borehole is H6=1.5*1307/30=66 ft The inside diameter of the openhole along this length of the openhole section of the borehole is Dh=0.323 ft And the outside diameter of the drill pipe tool joints along this length is D3=0.26 ft The total length of the drill collar increment (seventh), H7, in the openhole section of the borehole is H7=330 ft The inside diameter of the openhole along this length of the openhole section of the borehole is Dh=0.323 ft And the outside diameter of the drill collars along this length is D5=3.126/12=0.261 ft

TABLE 1: SEVENTH DEPTH INCREMENT

298

H1 (ft)

10616

D1 (ft)

0.515

D2 (ft)

0.292

H2 (ft)

558.75 D1 (ft)

0.515

D3 (ft)

0.388

H3 (ft)

2381

D4 (ft)

0.341

D2 (ft)

0.198

H4 (ft)

126

D4 (ft)

0.341

D3 (ft)

0.26

H5 (ft)

1242

Dh (ft)

0.323

D2 (ft)

0.198

H6 (ft)

66

Dh (ft)

0.323

D3 (ft)

0.26

H7 (ft)

330

Dh (ft)

0.323

D5 (ft)

0.261

1. Cased Section of the Annulus (Surface to 11175 ft) The first annulus section increment is denoted by the length H1. The temperature at the bottom of the length H1 in the cased annulus section of the borehole (bottom of the drill pipe body lumped geometry), T1, is T1=Tr+GH1=535+0.0154*10616=698.486 OR

The average temperature of this cased annulus section H1 is Tav=

Tr  T1 =616.74 OR 2

The approximate specific weight of the gas as it exits this cased annulus section and starts into the Tee is determined from PTee

 ga1 

Ptee  S =0.1141 R  Tr

The density of the gas as it exits this annulus section

 ga1 

 ga1 g

=0.1141/32.2=0.0035447 lbsec2/ft4

The kinematic viscosity of the gas at this location

 ga1 

 gas =0.000000251/0.0035447=0.0000708 ft 2/sec  ga1

The kinematic viscosity of the aerated drilling fluid mixture can be approximated with an average kinematic viscosity term. This average kinematic viscosity term can be defined by weight averaging the separate viscosities with the weight rates of flow of the separate fluids. Therefore, the kinematic viscosity term can be modified to determine the average kinematic viscosity of the mixture as it exits this annulus section. This is . .

 ava1 

.

wg  ga1  wm  m .

.

=0.0002413 ft2/sec

wg  wm

The approximate average velocity of the aerated drilling fluid as it exits this annulus section

299

Pg Va1 

Ptee



 4

Tg Tav

 Q g  Qm

( D12  D22 )

1826.6 616.74   19.67  0.178 =53.4 ft/sec  5729.89 519.67  2 2 (0.515  0.292 ) 4

The Reynolds number of the aerated drilling fluid as it exits this annulus section N Ra1 

53.4  (0.515  0.292) =49863.504 0.0002413

The Reynolds number calculation above is greater than 4,000. This indicates that the flow condition is turbulent. Therefore, the empirical von Karman equation is used to determine the approximate Fanning friction factor for the aerated flow in this annulus section.

Both annulus section surfaces are commercial steel with the surface roughness ep=0.00015 ft 2

f a1

    1   =0.02484   0.515  0.292     2 log 10  0.00015   1.14   

For the first increment in the annulus can be solved for the pressure at bottom of the increment, Pbh1. This involves selecting this upper limit by a trial and error procedure. The magnitude of the upper limit pressure on the left side of the equation is selected to allow the left side integral to equal the right side integral. The integration can be carried out on the computer using one of the commercial analytic software programs. The trial and error magnitude of the upper limit pressure that satisfies Equation for this annulus section is Pbh



5729.85

300

dP 2      1826.6  588.08         P  519.67 19.47  0.178   15.29 0.02484      1      2 2   1826.6  616.74 19.47  0.178   2  32.2(0.515  0.292)    ( 0 . 515  0 . 292 )   P  519.67       4      

So, Pbh1= 249876 lb/ft2

10616



 dh 0

The second annulus section increment is denoted by length H2. The temperature at the bottom of the length H2 in the cased annulus section of the borehole (bottom of the drill pipe tool joints lumped geometry), T2, is T2=Tr+G(H1+H2)=535+0.0154*(10616+558.75)=707.0912 OR

The average temperature of this cased annulus section H2 is Tav=

Tr  T2 =616.74 OR 2

The approximate specific weight of the gas as it exits this cased annulus section and starts into the annulus section above is determined from Pbh1 Pbh1  S =8.51663 lb/ft3 R  Tr

 ga2 

The density of the gas as it exits this annulus section

 ga2

 ga2 

g

=8.51663/32.2=0.264492 lbsec2/ft4


 ga2 

 gas =0.000000251/0.26449=0.000000949 ft 2/sec  ga2

The

average

kinematic

viscosity

of

the

mixture

at

this

position

. .

 ava2 

.

wg  ga1  wm  m .

.

=0.0002354 ft2/sec

wg  wm

The approximate average velocity of the aerated drilling fluid as it exits this annulus section Pg Va 2 

Pbh1



 4

Tav  Q g  Qm Tg ( D12  D22 )

1826.6 621.045   19.67  0.178 249876 519 . 67 =3.8667 ft/sec   2 2 (0.515  0.388 ) 4

The Reynolds number of the aerated drilling fluid as it exits this annulus section N Ra 2 

3.8667  (0.515  0.388) =2085.79 0.0002354

301

The Reynolds number calculation above is greater than 2,000 and less than 4,000. This indicates that the flow condition is transition. Therefore, the empirical Colebrook equation is used to determine the approximate Fanning friction factor in this annulus section Both annulus section surfaces are commercial steel with the surface roughness ep=0.00015 ft

By assuming ƒ=0.029

1 f a2

 e    Dh  D p  2 log 10   3.7   

   

  2.51   N R f a2   

This equation is solved by trial and error to find the value of fanning friction factor in this section ƒa2=0.02909

For the second increment in the annulus can be solved for the pressure at the bottom of the increment, Pbh2. This involves selecting this upper limit by a trial and error procedure. The magnitude of the upper limit pressure on the left side of the equation is selected to allow the left side integral to equal the right side integral. The integration can be carried out on the computer using one of the commercial analytic software programs. The trial and error magnitude of the upper limit pressure that satisfies Equation for this annulus section is

Pbh



249876

302

dP 2      1826.6  621.045         P  519.67 19.47  0.178   15.29 0.02909      1      1826 . 6 621 . 045 2  32 . 2 ( 0 . 515  0 . 388 )     2 2       (0.515  0.388 )   P  519.67 19.47  0.178      4      

So, Pbh2= 276302 lb/ft2

558.75



 dh 0

T HE CALCULATION IS REPEATED SIMILARLY FOR EACH SECTION TO DETERMINE THE PRESSURE AT THE BOTTOM OF IT

TABLE 2: GEOMETRY IN THE ANNULUS AT FIRST SECTION (H1=10616') First Cased section of annulus (surface to 11175 ft) Section increment H1=10616 ft T1

698.4864

Tav

616.7432

Specific weight of gas as it exit this cased annulus, lb/ft3 0.195298 the density of the gas as it exits this annulus section, lb.sec2/ft4

0.0060652

the kinematic viscosity of the gas at this location, ft2/s

4.138E-05

the average kinmetaic viscosity As it exit from the annulus, ft2/s

0.0002388

the average velocity as it exit from the annulus, ft/s

53.401496

Reynolds number at this section

49863.504

surface roughness (ep)

0.00015

Fanning friction factor in this annulus section

0.0248411

bottomhole pressure at this section, lb/ft2

249876

TABLE 3:GEOMETRY IN THE ANNULUS AT FIRS T SECTION (H2=558.75') Section increment H2=558.75 ft T2

707.0912

Tav

621.0456 Specific weight of gas as it exit this cased annulus, lb/ft3 8.51663

the density of the gas as it exits this annulus section, lb.sec2/ft4

0.2644916


9.49E-07

the average kinematic viscosity As it exit from the annulus, ft2/s

0.0002354


3.8666187


2085.7942


0.00015


0.0290963


276302

TABLE 4:GEOMETRY IN THE ANNULUS AT SECOND SECTION (H3=2381')

303

Second cased section of annulus (11175 to 13682 ft) Section increment H3=2381 ft T3

743.7586

Tav

639.3793

Specific weight of gas as it exit this cased annulus, lb/ft3

9.4173187


0.2924633


8.582E-07


0.0002354


5.5592341


3376.7697


0.00015


0.0281243


403860

TABLE 5:GEOMETRY IN THE ANNULUS AT SECOND SECTION (H4=126') Section increment H4=126 ft

304

T4

745.699

Tav

640.3495

Specific weight of gas as it exit this cased annulus, lb/ft3

13.764932


0.4274824


5.872E-07


0.0002354


7.4973875


2579.8079


0.00015


0.0334201

bottomhole pressure at this section, lb/ft

411667

TABLE 6:GEOMETRY IN THE ANNULUS AT OPEN HOLE SECTION (H5=1242') Open hole section (13682 to 15320 ft) Section increment H5=1242 ft T5

764.8258

Tav

649.9129

Specific weight of gas as it exit this open annulus, lb/ft3

14.031022


0.435746


5.76E-07


0.0002354


5.5951501


2971.0904


0.00015

Open hole roughness (eoh)

0.01

Average roughness (eav)

0.0073096


0.1641604


491427

TABLE 7:GEOMETRY IN THE ANNULUS AT OPEN HOLE SECTION (H6=66') Section increment H6=66 ft T6

765.8422

Tav

650.4211


16.749516


0.5201713


4.825E-07


0.0002354


9.3151502


2493.0959


0.00015


0.01


0.0061271


0.2435745


514670

305

TABLE 8:GEOMETRY IN THE ANNULUS AT OPEN HOLE SECTION (H7=330') Section increment H7=330 ft T7

770.9242

Tav

652.9621


17.541717


0.5447738


4.607E-07


0.0002354


9.3171588


2454.0711


0.00015


0.01


0.0061091


0.2463172


633405

2. Drill Bit Orifices and Nozzles The mixture of incompressible fluid and the compressed gas passing through the drill bit orifices or nozzles can be assumed to act as a single phase incompressible fluid. However, this assumption is valid only when the friction losses in the flow through the bit orifices are also assumed to be higher. Thus, borrowing from mud drilling technology,

It is assumed that the 3 7/8 inch impregnated drill bit is equipped with six 8/32 inch diameter jet nozzles

dn=0.25 inches=0.02083 ft

The equivalent single diameter for this drill bit

306

De  nDn2  6  0.020832 =0.051 ft

The approximate specific weight of the aerated fluid at the bottom of the annulus . .

 mixbh

.

.

wg  wm

1.28  13.98   =58.41 lb/ft3 Pg T7 1826.6 770.4942   19.47  0.178   Q g  Qm 633405 519.67 Pbh7 Tg

The pressure change in the aerated fluid through the drill bit, ΔPb, can be approximated by 2

. .   w g  wm  2  1.28  13.98   Pb   =22610.256 lb/ft2 2 2 2 g mixbhC 2  / 4 De4 2  32.2  58.41  0.812  / 4 0.0514

The pressure in the aerated fluid just above the drill bit inside the drill string, Pi7

Pi 7  Pbh  Pb =633405+22610.256=656015.26 lb/ft2=4556 psia

GEOMETRY INSIDE THE DRILLSTRING Starting at the bottom of the drill string, the total length of the drill collars increment, H7, in the openhole section of the borehole is H7=330 ft The inside diameter of the drill collars in this openhole section is D8=1.5/12=0.125 ft The total length of the drill pipe tool joints lumped geometry increment, H6, in the openhole section is H6=66 ft The inside diameter of the drill pipe tool joints lumped geometry in this openhole section is D9=1.5/12=0.125 ft The total length of the drill pipe body lumped geometry increment, H5, in the openhole section is H5=1242 ft The inside diameter of the drill pipe body lumped geometry in this openhole section is

307

D10=1.185/12=0.09875 ft The total length of the lumped drill pipe tool joints geometry increment, H4, in the second cased section is H4=126 ft The inside diameter of the drill pipe tool joints lumped geometry in this cased section is D9=0.125 ft The total length of the lumped drill pipe body geometry increment, H3, in the second cased section is H3=2381 ft The inside diameter of the drill pipe body lumped geometry in this cased section is D10=0.09875 ft The total length of the lumped drill pipe tool joints geometry increment, H2, in the first cased section is H2=558.75 ft The inside diameter of the drill pipe tool joints lumped geometry in this cased section is D11=3.4/12=0.283 ft The total length of the lumped drill pipe body geometry increment, H1, in the first cased section is H1=10616 ft The inside diameter of the drill pipe body lumped geometry in this cased section is D12=2.6/12=0.217 ft TABLE 9:TABLE 1: SEVENTH DEPTH INCREMENT INSIDE DRILLSTRING

308

H7 (ft)

330

D8 (ft)

0.125

H6(ft)

66

D9 (ft)

0.125

H5 (ft)

1242

D10 (ft)

0.09875

H4 (ft)

126

D9 (ft)

0.125

H3 (ft)

2381

D10 (ft)

0.09875

H2 (ft)

558.75 D11 (ft)

0.283

H1 (ft)

10616

0.271

D8 (ft)

Inside the Drill String (15320 ft to 13682 ft) The seventh drill string section increment is denoted by the length H7. The temperature at the bottom of the drill collars (bottomhole temperature) in the openhole section is T7=770.9242 oR The average temperature of the drill collar length H7 and, thus, the temperature of the aerated fluid flow inside the drill collars is Tav=652.9621 oR The approximate specific weight of the gas as it enters this drill collar section is determined as Pi 7  S =18.32 lb/ft3 R  Tr

 gi7 

The density of the gas as it enters this drill collar section

 gi7

 gi7 

g

=0.5689 lb.sec2/ft4


 gi7 

 gas =0.000000251/0.5689=0.0000004412 ft 2/sec  gi7

The

average

kinematic

viscosity

of

the

mixture

at

this

position

. .

 avi7 

.

wg  gi7  wm  m .

.

=0.0002354 ft2/sec

wg  wm

The approximate average velocity of the aerated drilling fluid as it enters this drill collar section Pg Vi 7 

Pi 7



Tav  Q g  Qm Tg

 4

=20.0656 ft/sec

2 8

(D )

The Reynolds number of the aerated drilling fluid as it enters this drill collar section

309

N Ri 7 

20.0656  (0.125) =10655.578 0.0002354

The Reynolds number calculation above is greater than 4,000. This indicates that the flow condition is turbulent. Therefore, the empirical von Karman is used to determine the approximate Fanning friction factor for the aerated fluid flow inside drill collars.

The inside surface of the drill collars is commercial steel with the surface roughness ep=0.00015 2

    1  =0.02052 f i7    0.125     2 log 10  0.00015   1.14    For the seventh increment inside the drill string can be solved for the pressure at the top of the increment, Pi6. This involves selecting this lower limit by a trial and error procedure. The magnitude of the lower limit pressure on the left side of the equation is selected to allow the left side integral to equal the right side integral. The integration can be carried out on the computer using one of the commercial analytic software programs. The trial and error magnitude of the lower limit pressure is

656015.26



Pi 6

dP 2      1826.6  588.08    19 . 47  0 . 178      P  519.67    15 . 29 0 . 0205157         1        1826.6  652.96    2  32.2(0.125)    (0.125 2 )   P  519.67 19.47  0.178      4        

So, Pi6=634600 lb/ft2 The calculation is repeated similarly for each section to determine the injection pressure at the surface.

310

330



 dh 0

T ABLE 10:GEOMETRY IN SIDE THE DRILL STING AT OPEN HOLE SECTION (H7=330') Open hole section of annulus (13682 to 15320 ft) Section increment H7=330 ft T7

770.9242

Tav

652.9621

Specific weight of gas as it enter this drill string section, lb/ft3

18.319895

the density of the gas as it enter this drillstring section, lb.sec2/ft4

0.5689408


4.412E-07

the average kinmetaic viscosity As it enters this drillstring section, ft2/s

0.0002354

the average velocity as it enters this drillstring, ft/s

20.065593


10655.578


0.00015

Fanning friction factor in this drillstring section

0.0205157

pressure at the top of the increment (injection), lb/ft2

634600

TABLE 11:GEOMETRY INSIDE THE DRILL STING AT OPEN HOLE SECTION (H6=66') Section increment H6=66 ft T6

765.8422

Tav

650.4211


17.791086


0.5525182


4.543E-07


0.0002354


20.230661


10743.185


0.00015


0.0205157


630329

311

TABLE 12:GEOMETRY INSIDE THE DRILL STING AT OPEN HOLE SECTION (H5=1242') Section increment H5=1242 ft T5

764.8258

Tav

649.9129


17.685166


0.5492288


4.57E-07


0.0002354


32.470615


13621.977


0.00015


0.021774


546990

TABLE 13: GEOMETRY INSIDE THE DRILL STING AT SECOND SECTION (H4=126') Second cased section of annulus (13682 to 11175 ft) Section increment H4=126 ft

312

T4

745.699

Tav

640.3495


15.576122


0.4837305


5.189E-07


0.0002354


20.180259


10716.172


0.00015


0.0205157


539142

T ABLE 14:GEOMETRY INSIDE THE DRILL STING AT SECOND SECTION (H3=2381') Section increment H3=2381 ft T3

743.7586

Tav

639.3793


15.375938


0.4775136


5.256E-07


0.0002354


33.854981


14202.395


0.00015


0.021774


389542

T ABLE 15:GEOMETRY INSIDE THE DRILL STING AT FIRST SECTION (H1=558.75') First cased section (11175 to surface ft) Section increment H2=558.75 ft T2

707.0912

Tav

621.0456


11.437413


0.3551992


7.066E-07


0.0002354


4.5666805


5489.856


0.00015


0.016904


361580

313

TABLE 16:GEOMETRY INSIDE THE DRILL STING AT FIRST SECTION (H1=10616') Section increment H1=10616 ft T6

698.4864

Tav

616.7432


12.323885


0.3827293


6.558E-07


0.0002354


5.1122938


5885.2763


0.00015


0.0170707


30129

The injection pressure while drilling at 15320 ft of depth is approximately 210 psia. This is the approximate injection pressure for both the compressed gas and the drilling mud as they enter the surface flow lines that lead to the top of the drill string. When drilling at a depth of 15320 ft, the corresponding injection pressure above is a air volumetric flow rate of 1,168 acfm (with a drilling mud volumetric flow rate of 80 gal/hr). This compressed air injection pressure is the pressure the compressor output must match. TABLE 17: SUMMERIZE THE PRESSURE PROFILE INSIDE THE ANNULUS & DS

314

H0

0

Pbh

39.8

Pi

209.2292

H1

10616

Pbh1

1735.25

Pi1

2510.972

H2

11175

Pbh2

1918.764 Pi2

2705.153

H3

13556

Pbh3

2804.583 Pi3

3744.042

H4

13682

Pbh4

2858.799 Pi4

3798.542

H5

14924

Pbh5

3412.688 Pi5

4377.285

H6

14990

Pbh6

3574.097 Pi6

4406.944

H7

15320

Pbh7

4398.646 Pi7

4556

Pressure profile pressure (psi)

0

1000

2000

3000

4000

5000

0 2000 4000

depth (ft)

6000 8000

in annulus in drill string

10000 12000 14000 16000 18000 FIGURE 2: PRESSURE PROFILE INSIDE THE ANNULUS AND DRILL STRING

Figure 2: shows the aerated drilling fluid (both air and mud) pressures in the annulus and inside the drill string as a function of depth for this illustrative example (while drilling at the depth of 15320 ft). The figure shows the pressure at the bottom of the annulus is approximately 4399 psia (Ph7 above). If a target oil or natural gas rock formation pore pressure at the bottom of the borehole is above this value, the oil or natural gas will flow into the borehole as the drill bit is advanced into the

315

producing rock formation. This would be underbalanced drilling. If the pore pressure is less than this value, rock cuttings from the advance of the drill bit will be forced into the exposed pores around the bottom of the borehole resulting in formation damage. To drill this borehole with an aerated drilling fluid from 13682 ft to 15320 ft and maintain a constant bottomhole pressure in the annulus of 4300 psig will require that volumetric flow rate of the compressed air be varied as the drilling progresses.

Compressor selection Product Specifications compressor

4-stage reciprocating

driver

Caterpillar d398TA V-12, turbocharged diesel engine

Driver rating

Rated 750 HP @ 900 RPM

Volume output

1250 SCFM @ 1150 PSIG discharge w/booster; 1200 SCFM @ 2100 psig discharge w/booster

cylinders

Cylinder 1:21'' bore Cylinder 2: 13-1/2 '' bore Cylinder 3: 8-1/4'' bore Cylinder 4: 4-3/4'' bore

Compressor dimensions/ weight

39' L X 13'11'' H/ weigh=84000 lbs.

Booster dimensions/ weight

39' L X 10' W X 13'11'' H/weight=84000 lbs+/-.

The compressor is a four-stage reciprocating piston compressor ns=4

316

The theoretical shaft horsepower, ˙Ws , required by the compressors is obtained from

 ns  k Pi  qi   Po Ws     k  1 229.17   Pi  .

.

K 1    ns k   1   

Where, 

K= specific heat ratio (equals 1.4 for nitrogen)



Qi= the input volumetric flow rate (acfm)



Pi=the input pressure (psia)



Po=the output pressure (psia)

1.4 1   4  1.4 12.685  1200   420  41.4  Ws      1 =264.1  0.4 229.17   12.685     .

.

The mechanical efficiency (em)=0.9 The first stage compressor ratio is P rs   o  Pi

  

1 / ns

 420     12.685 

1/ 4

=2.4

The volumetric efficiency (only for the reciprocating piston compressor), ev, is







ev  0.96 1  C rs1 / k  1

Where; C is the clearance volume ratio and equal 0.06 ev=0.91 The actual shaft horsepower required by each compressor . . .

W as

Ws  em  ev

=322.5

At this surface location, the input horsepower available from the Caterpillar Model D398 prime mover is a derated value (derated from the rated 760 horsepower available at 900 rpm). In order for the compressor units to operate, the derated input power available must be greater than the actual shaft power needed.

317

FIGURE 3: RIME MOVER PERCENTAGE REDUCTION IN POWER AS A FUNCTION OF ELEVATION ABOVE SEA LEVEL

W i  7601  0.1 =684 .

Prime Mover Fuel Consumption To estimate the total diesel fuel needed by the compressor unit it is necessary to estimate the fuel consumption of the compressor units’ Caterpillar Model D398, diesel fueled, turbocharged, prime mover.

The prime mover power ratio is .

PR 

Was .

=322.1/684=0.471=47.1%

Ws With the power ration percent, the approximate fuel consumption rate can be read on the ordinate using the diesel fuel curve. The approximate fuel consumption rate at this power level is 0.650 lb/hp-hr. The total weight of diesel fuel consumption per hour is .

318

W

.

f

 W i  0.65 =209.4 lb/hr

The diesel consumption rate q 'f 

209.4 =30.8 gal/hr 0.8156  8.33

Where 0.8156 is the specific gravity of diesel fuel and 8.33 is the specific weight of fresh water (lb/gal)

FIGURE 4:FUEL CONSUMPTION FOR GASOLINE, PROPANE/BUTANE, AND DIESEL

319

References 1. Bobo, R. A., and Barrett, H. M., “Aeration of Drilling Fluids,” World Oil, Vol 145, No. 4, 1953. 2. Graves, S. L., Niederhofer, J. D., and Beavers, W. M., “A Combination Air and Fluid Drilling Technique for Zones of Lost Circulation in the Black Warrior Basin,” SPE Drilling Engineering, February 1986. 3. Allan, P. D., “Nitrogen Drilling System for Gas Drilling Applications,” SPE 28320, Presented at the SPE 69th Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 25–28, 1994. 4. Underbalanced Drilling Manual, Gas Research Institute Publication, GRI Reference No. GRI-97/0236, 1997. 5. Gatlin, C., Petroleum Engineering: Drilling and Well Completions, Prentice-Hall, 1960. 6. Bourgoyne, A. T., et al, Applied Drilling Engineering, SPE, First Printing, 1986.

320

320

Overview of Bader El Din Petroleum Company The Badr El Din Petroleum Company (BAPETCO), is a joint venture serving the oil sector in. It was formed in the early 1980s, as joint venture between Shell and the Egyptian General Petroleum Cooperation. BAPETCO is responsible for the development and production of Shell’s fields in the Western Dessert.

BAPETCO is involved in the exploration and development of many concessions including Badr el Din, North East Abu Gharadig, Obaiyed, Sitra, Matruh and others

BAPETCO most important fields are: 1. 2. 3. 4. 5.

Badr 1 with volume production of 1800 barrels / day Badr 2 and produces about 70 million cubic feet gas per day Badr 3 located in the desert region about 250 km south of El Alamein Obaiyed Sitra

The Badr El Din Petroleum Company (Bapetco), ranks amongst Egypt's 10 largest joint venture operators. Daily production averages some 25 000 STB of oil and condensate and some 300 MMSCF of gas. The company aims to continuously increase value of its operations on behalf of the shareholders, by pursuing the following targets:  increase ultimate recovery and production rates;  reduce costs of developing hydrocarbon assets;  improve staff competence and efficiency;  Conduct a safe and environmentally friendly business .

321

FIGURE 2: BADR EL DIN

PETROLUM ACTIVATES

Obaiyed D-2 overview Concession: Obaiyed Well Name: Obaiyed D2ST Field DeirelSitta Well Type: UBD horizontal gas / condensate development well. Objectives: To prove the suitability of UBD as a technology that will unlock reserves in Obaiyed. To prove technique selected for drilling UBD in Obaiyed. To provide available +/-20 MMscf/day with drilling exposure of 1000m 3-7/8" hole. Background and Strategy: The well Oba D2 was drilled and completed in 1998. The well had penetrated the L. Safa formation at 3735mss, finding 19m of waste zone, 29m of Unit 3, 50m of Unit 4 and 15m of Unit 5 siliciclastics. The well was perforated in 2000, without recording any significant flow. The well was hence not tested, the conclusion is that the reservoir found in D2 does not produce due to tightness. The phase 2 FDP of May 2002 identified the D2 well as a key trial candidate to prove the feasability of underbalanced drilling in Obaiyed. The target of the well is Unit 3 in the area between D2 and JB 16-3SDT. This area has the following characteristics: 

Reservoir quality of Unit 3 is good at the JB 16-3SDT location, but deteriorates towards D2



he top reservoir structure is flat

To benefit from the increase in reservoir properties towards JB16-3SDT the D2 well is proposed to be sidetracked towards this well (to NW). Pending the reservoir quality found the well design is kept flexible to allow the well to be delivered with the optimum drain hole completion and geometry. The following case is based on the identification of poor reservoir during the initial OB drilling into the reservoir section: Poor (kh<0.01mD) reservoir means that the well will not flow after setting liner/perforating. UBD is a must to be able to flow the well. It is planned to test the well prior to handing over to production.

322

Geology of target horizon (Lower Safa): The D2ST well is targeting the Mesozoic Lower Safa reservoir in the northern part of the Western Block where Obaiyed 163/SDT, D7, D12 and 4H are located. The Lower Safa comprises a high N/G sequence of estuarine deposits, with a total thickness of some 90m in the area where D2ST is planned , although only 29m of these are considered productive. The sequence is made up of low permeable sandstone with some thin higher perm intervals. The sequence is subdivided into 5 distinct reservoir units, numbered from top to bottom and a 6th non-reservoir unit (called waste zone) which uncomformably / erosively overlies the sequence. Units 1-3 are the main reservoir units on which the bulk of the Obaiyed wells have been completed. They are composed of low to medium permeable (1-500 mD) micaceous sandstone deposited in a strongly tidally influenced estuary. Unit 4 is a non-reservoir unit composed of very fine to fine very micaceous sandstones, siltstones and mudstones which forms a seal between the deeper unit 5 and the other Lower Safa reservoir units. Unit 5 is composed of medium grained sandstones deposited under limited tidal influence. At the target location units 1 and 2 are eroded, leaving only relatively low quality unit 3 sandstones.

The Base Kabrit Mb/ top Lower Safa (Top prospective sequence) map shows a consistent fault pattern (predominant NW-SE en-echelon fault pattern) with the overburden horizons, which dissected the older deep seated NNE-SSW fault system. Petrophysical evaluation The reservoir pressure at the liner shoe and throughout the openhole sections will affect the ability to remain UB throughout. The current reservoir pressure estimate is ????psi (with a tolerance of +/- ???psi). If the BHP is less than this, maintaining UB conditions throughout the wellbore will be compromised and as such the drilling phase may have to be terminated earlier than initially planned. 

Porosity o Upper safa: The log porosities as determined by using the density log (10% porosity in D2), no cores were taken in U. Safa in wells D2 and Jbl6-3. o Lower safa The log porosities as determined by using the density log in D2 & JM6-3 were corrected using porosity measurements from cores which have been taken in D2 and JM6-3 in L.safa formation. Stress corrections were applied for cores porosity. Fig. 9 gives the complete evaluation of the cored wells OB A D2 and JB 16-3SDT.



Permeability o Lower Safa: Extensive core data allowes a good calibration with transform (permeability vs porosity relationship). The original D2 well found core permeabilities in the range of (0.25 : 1.5md ).

323

324

FIGURE 3: LOWER SAFA FORMATION TOPS

COO RDIN ATES

OBAIYED - D2

S U R FA C E TARG ET

Lat. Long. Lat. Long.

31 06' 56.13" 26 34' 27.54"

PROGNOSIS DEPTH mbdf (mss)

FMS.

323 756 659 394

ELEVATIONS GL. 203.77 m

m m

DF.

213.87 m

ACTUAL REMARKS

LITHOLOGY

N. E. N. E.

MARMARICA

DEPTH mbdf LITHOLOGY (mss)

FMS.

REMARKS

MARMARICA 164

Partial Total Losses

MOGHRA

173(-40)

MOGHRA

AP O

AP O LL ON

500

LL O NI A

332(118)

IA

333

793 + 30

819(605)

I 1000

KHOMAN

I

I

1073+ 30

I

KHOMAN 13 3 /8 " 1095 m

1092 m Heaving Swelling Shales

1500

ABU ROASH "A-F"

1583 + 30

ABU ROASH "A-F"

F 1600 (1386)

F

ABU ROASH "G"

Tight hole

ABU ROASH "G" 1830 (1620)

1843 + 30

MIDIEWAR

BAHARIYA

2000

BAHARIYA

13 3/8 "

1070 (856)

2073 + 30 2098 + 30

MIDIEWAR

KHARITA

2083 2109(1895)

2500

KHARITA

2623 + 30 2638 + 30

DAHAB

DOL. 2753 + 30

ALAMIEN

CL.

Caving

2843 + 30 2918 + 30

9 5 /8 "

3000

2965m Caving

D1

2753 2843

D2

9 5 /8 "

2942 (2728)

2972m

MASAJID

3500

K.O.P @ 3480

ZAHRA

3668 + 30

DARDUMA@3676(3456)

3758 + 30 F

KHATATBA@3760(3530)

UM A DA RD T LS

L. SAFA

3744 (3530) 3945 (3731)

3945 + 30

4000

KABRIT

3670 (3456)

KHATATBA

U. SAFA

L. SAFA SHIFAH ??

SHIFAH ??

L.SAFA@4102(3735)

Drilling Endded :-7.4.98 Core # 1 F/3941-T/3950 mbdf Rec. 8.2 m, 86% Core # 2 F/3950-T/3956.5 mbdf Rec. 6.5 m, 100% Core # 3 F/3956.5-T/3960.6 mbdf Rec. 3.8 m, 83% Core # 4 F/3960.6-T/3988.6 mbdf Rec. 28 m, 100% Core # 1,2,3,4

D1

3398 (3184)

3403 + 30

KHATATBA

CL.

MASAJID

ALAM EL BUIEB

D2

ALAM EL BUIEB

ALAMIEN

2639 2654

DAHAB

DOL.

3997 (3783)

T.D. 4115mbdf

T.D. 4125 mbdf

Schl. Run : 1) NGT / APS / LDL / AIT 2) GR / DSI / UBI / GPIT

Seismic Reflector Planned Core Interval

T.D. 4413 (3974)

Author : XGO

Date : 22.9.2002

Expected Gas Bearing Sand

Drawn by : XDF

FIGURE 4: OABYED D -2 FORMATION LITHOLOGY

Expected Oil Zone

325

Determination of the derrick load Derrick must be designed to carry safely all loads which ever be used while drilling, these loads are either: 

Vertical loads: o Dead load of derrick itself. o Dead load of the load supported by the C/B. o Live and impact load



Horizontal loads: o Hz. component of pipe set back. o Wind load . Wind load Lw = 0.004V 2  A , lb and V = 50 mph

.

Where: V is the wind velocity and A is wind load area

Note: Use maximum dead load capacity of a derrick equal to the heaviest casing column, an additional length (from 25 – 50 % of casing) is added for friction  Onshore well: Use Jack knife rig.  From its API specification: Determine the maximum casing weight  From the casing design For 13-3/8

Wc1=243559.68 lb

For 9-5/8

Wc2=459138.336 lb

For 7

Wc3=108722.16 lb

For 4.5

Wc4=1680 lb

It is obvious that 9-5/8'' casing has the maximum casing weight Buoyancy factor: BF== 1 – γm / γsteal =1-68.82/487.5=0.866 W c= 459138.336 * 0.866 = 397613.83 lb

326

By adding length 35% Maximum derrick load= 1.35  459138.33 =397613.83 lb≈ 400,000 lb

Note: For wind load, Wind load = 0.004 * (50)2 * 510 ft2 (for rig class 8A) = 5100, lb The derrick specifications are: from A Complete Well Planning Approach N. J. Adams Derrick size No.

18 A

Height

136

ft

Base square

30

ft

Casing capacity

400,000 lbs

Pipe size

5 in

Total length

8900 ft

Pipe weight

22.5 lb/ft

Wind load area

510 ft2

Swivel selection Maximum swivel rated dead load capacity = (Max. Drill string weight) +( Kelly weight ) = 295706+1055.5=296762 lb From the drilling data handbook we can select the appropriate design Depth capacity

15000 ft

Main bearing diameter

19.5 in

Fluid passage diameter

3 in

Hook clearance

22 in

Net approximate weight

3960 lb

327

Kelly selection From the drill string design, we can calculate the maximum drill string weight as follow; Max. Drill string weight = (weight of drill pipe+ weight of BHA+ weight of bit)max After considering the buoyancy factor and the safety factor Max. Drill string weight = (258745  170)  0.866 1.35 =295706 lb From the drilling data handbook we can select the appropriate design at maximum tensile yield of 322000 daN

Square 3.5 “ Lower pin connection (size & style)

Hexagonal 4.5 “ NC 38 C 3.5 IF

Lower pin connection (size & style)

NC 38 C 3.5 IF

Inside diameter

2.25

Inside diameter

2.25

Outside diameter

4¾

Outside diameter

4¾

Minimum recommend casing OD.

6 5/8

Minimum recommend casing O. D.

6 5/8

Internal pressure @ yield stress.

153.1

Internal pressure @ yield stress.

172.4

322000 daN

Tensile yield.

Then, the Kelly weight  Note:

Tensile yield.

322000 daN

  3.5 2  2.25 2   4 

144

 * 55 * 489.5  1055.5 lb. 

Most of rotating head are driven by a kelly driver. This attaches to the kelly and is mated to a machined piece on top of the bearing assembly. The kelly driver transfers rotation of the drillstring to the sealing element in the rotating head. The bearing assembly provides a seal and allows rotation of the stripper rubber while the bowl remains stationary. The stripper rubber is designed to rotate with the kelly since rotating the kelly within the stripper rubber would cause the stripper rubber to wear jut much faster.

328

Hexagonal kellys allow for a better seal than do square kellys. These should be used whenever possible for air drilling applications.

Hoisting system selection: Assume we select N = 8, Where : N is the number of lines strung over the block system. From the drilling data handbook we can determine the reeving efficiencies (E)

Plain bearing

K = 1.09

Friction factor = 0.692

Roller bearing

K = 1.04

Friction factor = 0.842

For hook load design  Total hook load during drilling Total hook load= Max. drill string weight+ Kelly weight+ swivel weight H. L = 295706 + 1055.5 + 3960 =301777 lb= 134.96 ton.  Total hook load during casing H. L = wt. of heaviest casing (9 5/8) = 459138.336 lb (from csg design) ≈ 205 ton From the composite drilling catalogue Model

Max. Hook load (ton)

Major hook opening (in)

Dimensions, L X W X H (in)

weight (lb)

H-250

250

7.5

100 X 30.7 X 29.5

4806

For traveling block load: Max. T/B weight = max total hook load +Hook weight = 459138.336+4806=463944.336 lb=207 ton Data for maximum hook load from Rotary Drilling Handbook at working load say 140 tons

329

API working load strength

450 tons

No. of sheaves

6

Sheave diameter

54 inch

Approximate weight

16105 lbs

Line size

1 3/8 inch, 1 1/4 inch

Overall length

119 3/8 inch

Overall weight

56 inch

Thickness

33 inch

Clevis width

8 1/2 inch

Length with hook

204,314 inch

Weight with hook

19,500 lbs

Hook length

101 1/2 inch

Hook width

33 inch

For Crown block design Total crown block load = T.H.L + D.L. tension+ F.L. tension    

Since, T.H.L=T.B. load + T.B. weight =215 ton The sheave efficiency can also determine from: Es=1/K=1/1.04=0.9615 D.L. tension= (H.L. /n) x (Esn /E) = (215/8) x (0.96158/0.842)=23.31 ton F.L.tension=31.82 ton

So, total crown block load=215+23.31+31.82=270.13 ton From Rotary Drilling Handbook page 140, select the following specification, API working load strength

325 tons

No. of sheaves

7

Sheave diameter

54 inch

Approximate weight

330

13995

lbs

Length “I” beam

108 inch

Diameter of sand line sheaves

24 inch

Drilling line

1 ½ inch

Length shaft, width block

49 ½ inch

Cat line

1 1/2 inch

Diameter of cat line sheaves

15 inch

For Drawing work design:  Draw work horsepower input

D/W H.P = Brake H.P./ EB = W m * Vmin / (33000 * EB ) Where:

   

33000 = (ft . lb / min) / h.p EB = Average efficiency factor for block and tackle system = 0.842 Vmin = Minimum expected velocity of the hook, assumed = 150 ft / min. W m = The total hook load, lb

D/W H.P = 480049.36* 150 / (33000 * 0.842) = 2591.49 hp ≈ 2592 hp. At this work horsepower input and from drilling data handbook select the following specification: Nominal Depth

16,000 ft

Drum diameter (D)

32 ,in

Drum length (B)

57 ,in

Drum Height

25 ,in

Approximates shaft diameter

1.2 ,ft

Length of skid (A)

25 ,in

Drope

2.625 ,in

Brake horsepower

1930.8, HP

331

 For fast line Max. Velocity = Brake.H.P./ Tf.l. = 1930.8*33,000 / (71266.24) = 894 ft/sec Where:

Tf.l. = 71266.24 lb

 Total length of the rope for wrapping N layers

L  N l  n Where:

 n=no. of coils in one layer  l=average length of one coil So , L 

Aa  B   ( D  A) * d 4 d

L=K*(A + D) *A*B

A, B and D can be determine from the above table K: constant depending on the rope diameter, equal to K 

 12 * d 2

 0.04

L=0.04*25*57*(32+25)=3119 ft

Calculation of derrick efficiency factor.

332

1

2

3

4

Line H.L

Leg A

Leg B

n T 4

n T 4

F.L T 2

Leg C

Leg D

Position

n T 4

n T 4

Between A,B,C,D

T 2

T 2

Between C,D

T 2

1 2

T

D.L

T 2

T 2

3

T

4

 For position 1: DEP=

CB  load T ( N  2) = =100% 4  Max  eq  Derrick  leg T ( N  2)

 For position 2: DEP=

CB  load T ( N  2) ( N  2) = = 4  Max  eq  Derrick  leg 4.( NT / 4  T ) ( N  4)

N=8 so, DEP= 83.3%  For position 3:

333

DEP=

CB  load T ( N  2) = 4  Max  eq  Derrick  leg T ( NT / 4  T )

N=8 so, DEP= 83.3%  For position 4: DEP= N=8

CB  load T ( N  2) N 2 = = 4  Max  eq  Derrick  leg 4.( NT / 4  3T / 2) N  6 so, DEP= 71.4%

Selection of mud pump Operating data: D/P

D/C

OD

4.5 inch

ID

3.826 inch

Length

12611.6ft

OD

6.5 inch

ID

3.5 inch

Length

270 ft

Hole

8.5 inch

Μud Viscosity

30 cp

ρm

10.05 ppg

YP ( yield point)

18lb/100 ft

 Pressure drop calculation Assume for fast drilling in soft formation, V = 180 ft/min Q: flow rate, gpm can be calculated as following,

334

Q = Annular area * Velocity

Q

  (8.5) 2  (4.5) 2   4 

ft gal.   180  7.48 =381.86 gpm min cu. ft 

144

 For pressure loss ∆Pt=∆Ps+∆ Pp+∆ Pc+∆Pp*+∆ Pc*+∆ Pb Where :       

∆ Pt ΔPs ΔPp ΔPc ΔPb ΔPc* ΔPp*

: total pressure loss, psi : total pressure loss in surface connection, psi : total pressure loss in d/p, psi : total pressure loss in d/c, psi : total pressure loss in bit, psi : total pressure loss in annulus outside d/c, psi : total pressure loss in outside d/p, psi

1. ΔPs : total pressure loss in surface connection: ΔPs =150 psi 2. ΔPp : total pressure loss in d/p:

Calculate the critical velocity

Vc 



1.08 p  1.08  p 2  9.3 m d 2  Y .P



12

md

Where :     

Vc: critical velocity, ft / sec. μp: mud viscosity= 30 c.p ρm: mud density = 10.04 ppg d: inside diameter d/p(ID) = 3.826 inch Y.P: yield point =18 lb/100ft

Vc 

1.08  30  1.08(302  9.3  10.04  3.8262 18)0.5 = 5.33 ft/sec. 10.04 * 3.826

335

 Calculate the actual velocity V

Q 2.45  d 2

Where :   

V : Actual velocity (average velocity), ft/sec. Q : flow rate, gpm d : inside diameter of d/p, inch. V

381.86 = 10.65 ft/sec 2.45  3.826 2 While V  VC ,

Then, turbulent flow.

Re 

Re 

2970  mV d

p

2970  10.04  10.65  3.826 = 40500 30

Then, from chart Gatlin Page ( 96 ) Ƒ = 0.006

So, Pp 

f  m LV 2 25.8d

0.0062  10.04  12612  10.65 2 Pp  = 872 psi 25.8  3.826

C- ΔPc: total pressure loss in d / c: C.1, using the following calculation

 Pressure loss inside d/c (ΔPc): 2-1 calculates the critical velocity,

Vc 

336



1.08 p  1.08  p 2  9.3 m d 2  Y .P

Where : d : inside diameter d/c, ft

md



12

Vc 

1.08  30  1.08(30 2  9.3  10.04  3.5 2  18) 0.5 =5.43 ft/sec 10.04  3.5

2-2 calculates the actual velocity, V

Q 2.45  d 2

Where : d : inside diameter of d/c, inch V

381.86 =12.7 ft/sec 2.45  3.5 2

While V  VC , Then, flow is turbulent.

Re 

2970  mV d

p

Where : d : inside diameter of d/c, inch Re 

2970  10.04  12.7  3.5 =44181.52 30

2-3 Then, from chart Gatlin Page (96 ) Ƒ = 0.0058

f m L V 2 Pc  25.8d Where : L : length of d/c ,ft d : inside diameter of d/c

Pc 

,inch

0.0058  10.04  270  12.7 2 = 28.1 psi 25.8  3.5

 ΔPd/p* : total pressure loss in annulus outside d/p: D-1

, using the following calculation 2-1 calculate the critical velocity,

337

Vc 



1.08 p  1.08  p 2  9.3 m d 2  Y .P



12

md

Where : d: clearance between open hole and D/P = 8.5 – 4.5 = 4 inch

1.08  30  1.08(30 2  9.3  10.04  4 2  18) 0.5 =5.29 ft/sec Vc  10.04  4

338

2-2 Calculate the actual velocity, V

Q 2.45  d 2

Where d2 = (diameter of OH)2 - (outer diameter of D/P)2 V 

381.86 =2.99 ft/sec 2.45  (8.5 2  4.5 2 )

While V  VC , Then,

flow is laminar.

 L   p  V   L  Y .P   P     1500  d 2   300  d   

 12612  30  3   12612  18      =203.73 psi P   2 2   1500  (8.5  4.5 )   300  (8.5  4.5)   E- ΔPc* : total pressure loss in annulus outside D/C: 2-1 calculate the critical velocity

Vc 



1.08 p  1.08  p 2  9.3 m d 2  Y .P



12

md

Where : d: the clearance between the open hole and OD of D/C=8.5-6.5=2 inch

Vc 

1.08  30  1.08(30 2  9.3  10.04  2 2  18) 0.5 =6.31 ft/sec 10.04  2

2-2 Calculate the actual velocity, V

V

Q 2.45  d 2

381.86 =5.195 ft/sec 2.45  (8.5 2  6.5 2 )

339

While V  VC , Then, flow is laminar

 L   p  V   L  Y .P   P     1500  d 2   300  d   

 270  30  5.195    270  18     =9.035 psi P   2 2   1500  (8.5  6.5 )   300  (8.5  6.5)  ΔPb : total pressure loss in bit:

Assume a cone bit has 3 nozzles 13/32, in with a bit nozzle coefficient C=0.95 Corrected value for multiple nozzle coefficient

d e  n  d 2 in Where :   

de : is the hydraulically equivalent single nozzle diameter, in. n : number of nozzle d : diameter of a nozzle, in

d e  3 13 / 32 =0.7036 2

The pressure drop in the bit calculated from the following equation Use the eqn. Pb 

Pb 

q2  m 7430  C 2  d e

4

381.86 2  10.04 =890 psi 7430  0.95 2  0.7036 4

P  150  872  28.1  203.73  9.035  890  2153 psi

340

Selection of the wellhead for Obayed D-2 The safest procedure for designing preventer pressure ratings is to ensure that the preventer can withstand the worst pressure condition possible. This condition occur when all drilling fluids have been evacuated from the annulus and only low density from fluids such as gas remain, so

1. Maximum formation pressure = P h – 200 psi Ph = 0.052*9.04*13000 =6110 psi. Pfmax = 5910 psi 2. Determine minimum hydrostatic pressure assume only gas density = 1 ppg Phmin = 0.052 * 1 * 13000 = 676 psi. Also, the operator’s experience should dictate that 80 % design factor would be unexpected eventualities. 3. Working pressure = resultant pressure * 0.8= (P fmax. – Phmin) * 0.8 = 4350 psi Using the API designations at 5000 psi working pressure and from the drilling data handbook

Selection of Flange At the 5000 working pressure, there are two flanges types Type

Nominal size, in

6B

2 1/16 – 11

6 BX

13 5/8 – 21.25

Select API type 6BX flange with nominal size of 13 5/8 Nominal Size

13 3/8 in

Outside diameter (OD)

26.5 in

Diameter of raised face (K)

18 in

Total thickness (T)

4.94 in

Large diameter of hob (J1)

18.94 in

Small diameter of hob (J2)

16.69 in

Selection of bolts

341

Bolt circle diameter

23.25 in

Number of bolt

16

Diameter of bolt

1.625 in

Length

12.5 in

Ring joint

160

Selection of BOP rams Operating data CAMERON RAM TYPE "U" BLOW –OUT PREVENTOR

Nominal size (in)

fluid volume (gallon)

working prssure(psi)

To open 13 5/8

5,000

5.8

To close

close ratio

5.45

open ratio

7

2.3

Dimensions & weight Width bonnets closed locking rams (scrwed)

112.125 in

Width bonnets open locking rams (unscrwed)

171.5 in

Single BOP

Hight between flanges (in)

33.812

Weight, lb

7700


55.875

Weight, lb

14800

Double BOP

342

Selection of HYDRIL rams

Operating data

CAMERON HYDRIL TYPE "MPL" BLOW –OUT PREVENTOR

Nominal Size (in)

Working pressure (psi)

13 5/8

5000

Fluid volume (gal) To open

To close

5.2

5.9

Open ratio

Close ratio

5.2

2.1

Dimensions & weight

Width bonnets closed locking rams (scrwed)

116 ¾ in

Width bonnets open locking rams (unscrwed)

52.25 in

Single BOP


36.25

Weight, lb

8850


58 1/8

Weight, lb

16700

Double BOP

343

Design of drill string First: drill collars: Like drill pipe, drill collars are subjected to stresses due to: 1234-

Buckling and bending forces. Tension. Vibrations. Alternate compression and tension.

Firstly: Drill collar selection:

1- Choose from the above table the recommended DC sizes ( ID, OD ).and specify its nominal weight.

W f  2.67( D p2  Di2 ) Minimum collar OD  2 ( casing coupling OD) - (bit sub) 2- Calculate the length of drill collar used using:

WOB  Ldc  wt dc  B.F  0.85 B.F  1  Ldc 

 mud (  steel  65.5 ppg )  steel

WOB wt dc  B.F  0.85

Where: 

WOB= weight on bit, lb



Ldc= length of drill collar, ft



Wtdc= nominal weight of drill collar, ft



B.F.= buoyancy force



Safety factor=0.85

3- Calculate number of joints of drill collar used:

344

Ndc =Ldc / 30

Secondly: drill pipe selection: Its Function is to transmit rotation and drill mud under pressure to bit where it is subjected to different types of loading:

The drill pipe Grade: "THE MOST COMMON USED IN OUR DESIGN IS GRADE G" Length of DP: Length of D/P= total length – length of D/C (BHA) Third: Bottom hole assembly design: The lower portion of the drill string, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavyweight drill pipe, jarring devices ("jars") and crossovers for various thread forms.

Calculations: For hole size (17 1/2) @ MD = 1099 m & TVD = 3968.87 m First drill collar design: For hole size (17 1/2) @ MD = 1099 m & TVD = 3968.87 m Hole (in)

WOB (klb)

Depth (m)

MW(ppg)

17.5

25

1099

8.8

OD (in)

8

ID (in)

3.5

N.W (lb/ft)

138.1725

BF

0.865649

WOB (lb)

25000

weight of DC in air

28880.07

Ldc (ft)

245.8995

Weight of D/C to get 85%(SF) of collars for WOB

33976.55

No. of joint of DC actually used

8.196651

new length of DC

rounded up to

9

270

Heavy weight drill pipe design (HWDP): HWDP specification: OD (in)

ID (in) 5

3-

N.W (lb/ft)

length (ft)

49.3

300

It was decided to run 300 ft of HWDP for transition purpose and to also be used for weight on bit then the amount of drill collars used can be reduced.

345

Weight of HWDP (lb)

14790

New weight of D/C after taking weight of HWDP

19186.55

New length of D/C in feet

138.8594

No. of joint of D/C

4.628647

new length according to the rounded value (ft)

150

length of BHA (ft)

450

weight of BHA (lb)

34623.65

Tension @ top of HWDP if max pull is applied=MOP+ BHA weight

134623.7

rounded up to

5

Second drill pipe design: Drill pipe selection: Grade

OD

ID

G105

4.5

3.826

NW 16.6

EW 14.98

thickness 0.337

Collapse resistance 9467

Internal yield 12581

pipe body yield 364231

torsional yield 33795

1st: check for tensile: Max. allowable design load in tension

327807.9

max. length of pipe (ft)

319698

length of DP (ft)

3154.72

No. of stands of DP

33.92172

new length of DP according to the rounded value (ft)

3162

new weight of DP (lb)

52489.2

The max. design tension load = DS weight * BF

75409.14

Tension design factor

4.347058

Since S.F is greater than 1.125 so it's accepted.

346

rounded up to

34

2nd: check for collapse: The max. design collapse pressure

5956.988

Collapse design factor

1.589226 Since S.F is greater than 1.125 so it's accepted.

3rd: check for torsion: Max. length of the hole

13017.89

Jar distance from the bit

100

Max. free point that could occur

12917.89

cross sectional area

4.405203

polar moment of yield inertia

19.21124

Minimum unit yield strength (psi)

82681.99 214437

Minimum yield strength (Lb-ft) D/P torsion strength

27436.79

Torsion safety factor

1.23174

accepted

For bottom hole assembly design: Item

Description

OD (in)

ID (in)

Weight (lb/ft)

length (m)

Length (ft)

1

bit

17.5

3

795.63

0.75

2.46

2

bit sub

9.5

3

217.48

1

3.28

3

DC

8

3.5

138.1725

9.14

235.0171

4

integral blade stabilizer

8

3

217.48

1

3.28

5

DC

8

3.5

138.1725

18.28

235.0171

8

jar

8

2.81

150.17

9.14

29.9792

9

DC

9.5

3.5

208.26

18.28

235.0171

10

cross over sub

8

2.81

150.17

0.75

2.46

11

10xHVWDP

5

3

49.3

91

298.48

No. of DC used

1

2

2

10

For hole size (12 1/4) @ MD = 2980 m & TVD = 3968.87 m

347

First drill collar design: Depth (m) 2980

Hole (in)

WOB (klb)

MW(ppg)

12 1/4

18

9.2

OD (in)

8

ID (in)

3.5

N.W (lb/ft)

138 0.859542

BF

18000

WOB (lb) weight of DC in air

20941.39

Ldc (ft)

178.3056


24636.92


5.943518

rounded up to

6

180

new length of DC

Heavy weight drill pipe design (HWDP): HWDP specifications: OD (in)

ID (in)

N.W (lb/ft)

length (ft)

5

3

49.3

300

It was decided to run 300 ft of HWDP for transition purpose and to also be used for weight on bit then the amount of drill collars used can be reduced. Weight of HWDP (lb) New weight of D/C after taking weight of HWDP

9846.924


71.26544

No. of joint of D/C

2.375515


90

length of BHA (ft)

390

weight of BHA (lb)

27225.53


127225.5

Second drill pipe design:

348

14790

rounded up to

3

Drill pipe specification: Grade

OD

ID

NW

EW

thicknes s

Collapse resistance

Internal yield

pipe body yield

torsional yield

G105

4.5

3.826

16.6

14.98

0.337

9467

12581

364231

33795

1st check for tensile: Max. allowable design load in tension

327807.9


12083.28 9384.4

length of DP (ft)

100.9075

No. of stands of DP new length of DP according to the rounded value (ft)

rounded up to

101

9393


155923.8

the max. design tension load = DS weight * BF

157424.5


2.082318

Since S.F is greater than 1.125 so it's accepted. 2nd: check for collapse: the max. design collapse pressure

6227.76


1.520129

Since S.F is greater than 1.125 so it's accepted. 3rd: check for torsion: Max. length of the hole

13017.89


226

Max. free point that could occur

12791.89

cross sectional area

4.405203


19.21124


82681.99

Minimum yield strength (Lb-ft)

212345.4

D/P torsion strength

27579.71


1.225357

349 accepted


Description

OD (in)

ID (in)

Weight (lb/ft)

Length (m)

Length (ft)

12.25

3

377.57

0.3

0.984

1

bit

2

NB stabilizer

8

3

147.22

1.5

4.92

3

DC

8

3.5

138.1725

9.14

29.9792

4

ST. stabilizer

8

2.81

150.17

2

6.56

5

DC

8

3.5

138.1725

18.28

59.9584

6

jar

8

2.81

150.17

9.14

29.9792

7

DC

8

3.5

138.1725

9.14

29.9792

8

cross over sub

8

2.81

150.17

0.75

2.46

9

10xHVWDP

5

3

49.3

91

298.48

No. of DC used

1

1

1

10

For hole size (8 1/2) @ MD = 4115 m & TVD = 3968.87 m First drill collar design: Depth (m)

Hole (in)

WOB (klb)

MW(ppg)

4115

8 1/2

15

10.05

OD (in)

6.5

ID (in)

3.5

N.W (lb/ft)

80

BF WOB (lb)

15000

weight of DC in air

17718.6655

Ldc (ft)

260.243306


20845.4888


8.67477685

new length of DC

350

0.84656489

270

rounded up to

9

Heavy weight drill pipe design (HWDP): HWDP specification: OD (in)

ID (in)

N.W (lb/ft)

length (ft)

5

3

49.3

240

It was decided to run 240 ft of HWDP for transition purpose and to also be used for weight on bit then the amount of drill collars used can be reduced. Weight of HWDP (lb)

11832


9013.48878


112.52795

No. of joint of D/C

3.75093166


120

length of BHA (ft)

360

weight of BHA (lb)

40668


140668

rounded up to

4

Second: Drill pipe design: Drill pipe specifications: Grade

OD

ID

NW

EW

thicknes s

Collapse resistance

Internal yield

pipe body yield

torsional yield

G105

4.5

3.826

16.6

14.98

0.337

9467

12581

364231

33795

1st check for tensile: Max. allowable design load in tension

327807.9


11273.488 13137.2

length of DP (ft)

141.260215

No. of stands of DP new length of DP according to the rounded value (ft)

rounded up to

142

13206 219219.6

new weight of DP (lb) The max. design tension load = DS weight * BF

220011.716 1.48995656

Since S.F is greater than 1.125 so it's accepted.

351

2nd: check for collapse: the max. design collapse pressure

6803.1512


1.39156102

Since S.F is greater than 1.125 so it's accepted. 3rd: check for torsion: Max. length of the hole

13017.8936


104

Max. free point that could occur cross sectional area

12913.8936 4.30965


10.2408058


81414.5

Minimum yield strength (Lbft)

200165.351


18814.7971


1.20144798

accepted


Description

OD (in)

ID (in)

Weight (lb/ft)

Length (m)

1

bit

8.5

2.8

172.4

0.3

2

bit sub

7.5

3

58.3

4.12

3

drill collar

6.5

3.5

80.1

9.14

4

blade stabilizer

6.75

3

254.4

1.5

5

drill collar

6.5

3.5

80.1

9.14

6

jar

5

3

42.83

9.14

7

drill collar

6.5

3.5

80.1

18.28

8

cross over sub

6.75

3

254.4

0.3

9

8x HWDP

5

3

49.3

72 123.92

352

No. of DC used

1

1

2

For hole size (6) @ MD = 4115 m & TVD = 3968.87 m First drill collar design: Depth (m)

Hole (in)

WOB (klb)

MW(ppg)

4,171

6

5

9.3

OD (in)

4.75

ID (in)

2.6

N.W (lb/ft)

42

BF

0.85801527

WOB (lb)

5000

weight of DC in air

5827.40214

Ldc (ft)

383.06267


6855.76722


12.7687557

new length of DC

rounded up to

13

390

Heavy weight drill pipe design (HWDP): HWDP specifications: OD (in)

ID (in)

N.W (lb/ft)

length (ft)

3.5

2.063

21.4

180

It was decided to run 180 ft of HWDP for transition purpose and to also be used for weight on bit then the amount of drill collars used can be reduced. Weight of HWDP (lb)

3852


3003.76722


71.1916753

No. of joint of D/C

2.37305584


90

length of BHA (ft)

270

weight of BHA (lb)

15244.0223

rounded up to

3

353

Second: Drill pipe design: Drill pipe specifications: torsional yield

pipe body yield

Internal yield

Collapse resistance

thickness

EW

NW

ID

OD

grad e

22605

3580868

21552

20260

0.449

14.63

15.5

2.6

3.5

G105

1st: check for tensile: 315781.2

Max. allowable design load in tension

12937.8824


13410.88 146

rounded up to

length of DP (ft)

144.203011

No. of joints of stand

13578


210459


193656.639

the max. design tension load = DS weight * BF

1.63062419


Since S.F is greater than 1.25 so it's accepted. 2nd: check for collapse: 6295.45334

The max. design collapse pressure

3.21819556


Since S.F is greater than 1.25 so it's accepted. 3rd: check for torsion: 13017.8936 91 12926.8936 4.30965 10.2408058 81414.5

354

accepted

Max. length of the hole Jar distance from the bit Max. free point that could occur cross sectional area polar moment of yield inertia Minimum unit yield strength (psi)

200366.851

Minimum yield strength (Lb-ft)

18805.652


1.20203224



Description

OD (in)

ID (in)

Weight (lb/ft)

Length (m)

1

tri cone bit

6

2.8

75.37

0.3

2

Motor W/1.15 bent housing

5.25

3.5

40.99

9.06

3

MWD

4.75

3

4

DC

4.75

2.6

18.0225

9.14

5

Jar

4.75

3

36.3

9.14

6

DC

4.75

2.6

18.0225

18.28

7

8x HWDP

3.5

2.063

25.3

115.853659

No. of DC

9.14 2

1

170.913659

For hole size (3 7/8) @ MD = 4115 m & TVD = 3968.87 m First drill collar design:

Depth (m)

Hole (in)

WOB (klb)

MW(ppg)

4670

3 7/8

2

8.4

OD (in)

3.125

ID (in)

1.5

N.W (lb/ft)

20

BF WOB (lb)

0.87175573 2000

weight of DC in air

2294.22067

Ldc (ft)

317.095973


2699.08314


10.5698658

new length of DC

330

length of BHA (ft)

330

weight of BHA (lb)

6622.01719


106622.017

rounded up to

11

355

Second: Drill pipe design: Drill pipe selection: Grade

OD

ID

NW

EW

thickness

Collapse resistance

Internal yield

torsional yield

G105

2.375

1.185

6.65

6.62

0.28

18726

19806

6735

1st check for tensile:

Max. allowable design load in tension

135595.8


4356.95982

length of DP (ft)

14987.6

No. of stands of DP

161.156989


rounded up to

162

15066


100188.9

The max. design tension load = DS weight * BF

93113.0286


1.45624949

Since S.F is greater than 1.125 so it's accepted 2nd: check for collapse: The max. design collapse pressure

5686.21592


3.29322703

Since S.F is greater than 1.125 so it's accepted. For bottom hole assembly design: Clean out assembly for installing 7'' tie back string Item

356

Description

1

Drill pipe

2

OD

ID

3 ½”

2.6”

Top

Bottom

XTM-39 Box

XTM-39 Pin

X/O

XTM-39 Box

3 ½” IF pin

3

X/)

3 ½” IF Box

4 ½” IF Pin

4

Top dress mill

4 ½” IF box

4 ½” IF box

5

Tandem Polish Mill

4 ½” IF pin

-

Drilling horizontal section

8 ¼” 7 7/16”

-

Length As rqd

item

Item

OD

ID

Top

Bottom

Length

2.6”

XTM-39 Box

XTM-39 Pin

As rqd

XTM-39 Box

WT-23 Pin

WT-23 Box

WT-23 Pin

1

Drill pipe

3 ½”

2

X/O (cross over)

3 ½”

3

Drill pipe

2 7/8”

4

X/O

3 1/8”

WT-23 Box

2 7/8” PAC Pin

5

Drill collar

3 1/8”

2 7/8” PAC Box

2 7/8” PAC Pin

6

Stabilizer

3 3/8”

2 7/8” PAC Box

2 7/8” PAC Pin

7

Motor

3 1/8”

2 7/8” PAC Box

2 3/8” Reg Pin

1.815”

-

As rqd

+/- 60m

Drilling under balance assembly: Item

Description

OD

ID

Top

Bottom

Length

Drill pipe

3 ½”

2.6”

XTM-39 Box

XTM-39 Pin

As rqd

X/O

3 ½”

XTM-39 Box

WT-23 Pin

Drill pipe

2 7/8”

WT-23 Box

WT-23 Pin

X/O

3 1/8”

WT-23 Box

2 7/8” - 6SA Pin

MWD/GR/PWD

3 1/8”

2 7/8” - 6SA Box

2 3/8” Reg Pin

NRV (2)

3 /18”

2 3/8” Reg Box

2 3/8” Reg Pin

X/O

3 1/8”

2 3/8” Reg Box

2 3/8” PAC Pin

Turbine

2 7/8”

-

2 3/8” PAC Box

2 3/8” Reg Pin

Impreg Bit

3 7/8”

-

2 3/8” reg Box

-

1.815”

-

As rqd

48.33’

BHA Summary Report Top Side BHA Diagram

357

PBR Dressing BHA

3.5" XTM39 MU Torque 14,700# - 23,300#

3 ½" XTM39 GTDP Weatherford

3.5" XTM39 Pin MU Torque 14,700# - 23,300# 3 ½" XTM39 Box Crossover to 3 ½" IF Pin EDC

3 ½" x 4 ½" IF Crossover Rig

3.5" XTM39 Box MU Torque 14,700# - 23,300#

3 ½" IF Pin MU Torque 9,900# 3 ½" IF Box MU Torque 9,900#

4 ½" IF Pin MU Torque 29,500# 4 ½" IF Box MU Torque 29,500#

8 ¼" Top Dress Mill

4 ½" IF Box MU Torque 29,500# 4 ½" IF Pin MU Torque 29,500#

7 7/16" Tandem Polish Mill

358

Drilling BHA 3.5" XTM39 Box MU Torque 14,700# - 23,300# 3 ½" XTM39 GTDP

3 ½" XTM39 NRV

Weatherford

Weatherford

3.5" XTM39 Pin MU Torque 14,700# - 23,300#

3 ½" XTM39 Crossover to 2 7/8" WT23

3.5" XTM39 Box MU Torque 14,700# - 23,300#

Weatherford

2 7/8" WT23 Pin MU Torque 2,200# - 8,300#

2 7/8" WT23 Box MU Torque 2,200# - 8,300# 2 7/8" WT23 GTDP Weatherford 2 7/8" WT23 Pin MU Torque 2,200# - 8,300# 2 7/8" WT23 Crossover to 2 3/8" Reg Weatherford

2 7/8" WT23 Box MU Torque 2,200# - 8,300#

2 3/8" Regular Pin MU Torque 2,600# 2 3/8" Regular Torque 2,600#

2 3/8" Reg MWD Tool Sperry Sun 2 3/8" Regular Pin MU Torque 2,600# 2 3/8" Reg Box MU Torque 2,600# 2 x 2 3/8" NRV’s Weatherford 2 3/8" Reg Pin MU Torque 2,600# 2 3/8" Regular Cross Over 2 3/8" Pac

2 3/8" Reg Box MU Torque 2,600# 2 3/8" Pac Pin MU Torque 2,600#

Weatherford 2 3/8" Pac Box MU Torque 2600#

2 7/8" Turbine Neyrfor

2 3/8" Regular Pin Torque 2,600# 3 7/8" Smith / HCC

2 3/8" Regular Box Torque 2,600#

359

Casing and Tubing Design Casing is the major structural component of a well. Casing is steel pipe that is run into the wellbore and usually cemented in place.

There are several reasons For Using Casing:       

To prevent the hole from caving in Or Collapse Onshore - to prevent contamination of producing To prevent water migration to producing formation To confine production to the wellbore To control pressures during drilling To provide an acceptable environment for subsurface equipment To enhance the probability of drilling to total depth (TD)

In addition, Casing provides locations for the installation of blowout preventers (BOP’s), wellhead equipment, production packers.

i.

Casing Type : 1 - Conductor. 2 - Surface. 3 - Intermediate.

360

4 - Production. 5 - Liner.

1) Conductor casing: Is set below the drive pipe or marine conductor that is run to protect loose, near surface formations and enable circulation of drilling fluid, it Prevents Washing-Out around the base of the rig. Function : o o

The conductor isolates unconsolidated formations and water sands Protects against shallow gas.

2) Surface casing: The surface casing is the first string of any sequence to be run into a well, after a hole has been drilled. Diameter of the surface casing must obviously be less then the diameter of the conductor, if a conductor was run. It ranges from (7 5/8)" to 20" commonly (13 3/8)". Attached to the surface Casing, after it has been cemented, is the following pieces of equipment. Casing head from which part of the suspended weight of subsequent strings are hang. Functions : o The surface casing is also designed to seal off fresh water aquifers and prevent them from being contaminated by hydrocarbons or salt water, which may be encountered in deeper drilling. o Provides blowout protection, isolates water sands, and prevents lost circulation o In deviated wells, the surface casing may cover the build section to prevent key seating of the formation during deeper drilling 3) Intermediate casing: Isolates unstable hole sections, lost circulation zones, low pressure zones, and production zones. The size ranges from (6 5/8)" to 20 "and commonly (9 5/8)". 4) Production casing: Isolates production zones and contains formations pressures in the event of a tubing leak. It may also be exposed to injection pressure from fracture jobs down casing, gas lift, or the injection inhibitor oil. 5) A Liner: Is a casing string that does not extend back to the wellhead, extending from the bottom of a well to a point 100 feet-or more the lower end of the intermediate string. Liners are used to reduce cost, improve hydraulic performance during deep drilling, and allow the use of larger tubing above the liner top.

361

A Tieback string: a casing string that provides additional pressure integrity from the liner top to the wellhead. Used when it is necessary to extend an existing liner further up hole, with a tieback casing string.Is Reasons for running tieback string:

 Cover casing above the top of liner.  Cementing of troubles intervals.  Selective testing of multiple zones to design future production assemblies and production casing size.

i.

362

Effect of pressure in B or C annulus

ii.

properties of casing: Casing is classified according to Six properties:  Outside diameter of pipe (e.g. 9 5/8”)  Wall thickness (e.g. 1/2”)  Grade of material (e.g. N-80)  Type to threads and couplings (e.g. API LCSG)  Length of each joint (RANGE) (e.g. Range 3)

 Nominal weight (Avg. wt/ft incl. Wt. Coupling) (e.g. 47 lb/ft) iii.

Determine the number of casing string needed and their setting depth

1) Determine the hydrostatic pressure : Ph  0.052 *  m * h,

psi

wher,

 m is mud density,

ppg

h is depth, ft 2) Determine the formation pressure : Pf  Ph  200,

psi

3) Determine the fracture pressure : Pfr 

 1 

 v  Pf  Pf ,

psi

where,

 is poisson ratio  0.3  v is vertical overburden stress  1 psi / ft 4) Plot Hydrostatic, formation, and fracture pressure gradient against depth. 5) Plot another curve equal fracture pressure -0.5 ppg for safety.

363

6) From plotting we can find the number and setting depth of the casing string

364

Depth

Dept h

Ph

Pf

Mud Weight

ft

m

Psi

Psi

ppg

1305.4 4

398

596. 7

396.73 1

8.790598 29

1476

450

674. 7

474.69 6

8.790598 29

2476.4

755

119 6

996.30 8

9.290064 1

3562.0 8

1086

176 7

1567.0 4

4127.8 8

1258. 5

215 5

4127.8 8

1258. 5

4880.6 4

Mud Type

Mud gradient

Pore gradient

frac gradient

Kick margin

psi/ft

psi/ft

psi/ft

psi/ft

0.4571111 11

0.3039060 61

0.5359373 74

0.3827323 25

0.4571111 11

0.3216097 56

0.5477398 37

0.4122384 82

0.4830833 33

0.4023209 36

0.6015472 91

0.5207848 94

9.539797

0.4960694 44

0.4399224 74

0.6266149 83

0.5704680 12

1954.9 3

10.03926 28

0.5220416 67

0.4735906 46

0.6490604 31

0.6006094 1

215 5

1954.9 3

10.03926 28

0.5220416 67

0.4735906 46

0.6490604 31

0.6006094 1

1488

233 2

2132.4

9.190170 94

0.4778888 89

0.4369106 57

0.6246071 04

0.5836288 72

6038.4 8

1841

291 7

2717.0 9

9.290064 1

0.4830833 33

0.4499624 15

0.6333082 77

0.6001873 59

6523.9 2

1989

313 5

2934.6 5

9.240117 52

0.4804861 11

0.4498296 96

0.6332197 97

0.6025633 82

6888

2100

329 2

3091.7

9.190170 94

0.4778888 89

0.4488528 84

0.6325685 89

0.6035325 85

7097.9 2

2164

337 4

3173.5 8

9.140224 37

0.4752916 67

0.4471143 98

0.6314095 99

0.6032323 3

7452.1 6

2272

354 2

3341.9 5

9.140224 37

0.4752916 67

0.4484538 1

0.6323025 4

0.6054646 84

7855.6

2395

371 3

3513.3

9.090277 77

0.4726944 44

0.4472349

0.6314899 33

0.6060303 88

8118

2475

383 7

3637.3 3

9.090277 77

0.4726944 44

0.4480578 34

0.6320385 56

0.6074019 46

8413.2

2565

397 7

3776.8 7

9.090277 77

0.4726944 44

0.4489222 77

0.6326148 51

0.6088426 84

8760.8 8

2671

416 4

3963.9 7

9.140224 37

0.4752916 67

0.4524629 1

0.6349752 73

0.6121465 16

9193.8 4

2803

439 4

4193.6 3

9.190170 94

0.4778888 89

0.4561351 93

0.6374234 62

0.6156697 66

9456.2 4

2883

420 0

3999.7 5

8.540865 38

0.444125

0.4229749 45

0.6153166 3

0.5941665 74

9882.6 4

3013

436 3

4163.4 6

8.490918 81

0.4415277 78

0.4212902 7

0.6141935 14

0.5939560 06

10230. 32

3119

483 6

4635.8 2

9.090277 77

0.4726944 44

0.4531447 14

0.6354298 09

0.6158800 79

Spud Mud

Kclpolym er

365

366

10489. 44

3198

512 2

4921.7 6

9.389957 27

0.4882777 78

0.4692109 83

0.6461406 55

0.6270738 61

10705. 92

3264

531 1

5110.8 8

9.539797

0.4960694 44

0.4773881 91

0.6515921 28

0.6329108 75

10791. 2

3290

535 3

5153.1 8

9.539797

0.4960694 44

0.4775358 24

0.6516905 5

0.6331569 3

10791. 2

3290

535 3

5153.1 8

9.539797

0.4960694 44

0.4775358 24

0.6516905 5

0.6331569 3

10837. 12

3304

540 4

5204.1 1

9.589743 6

0.4986666 67

0.4802115 79

0.6534743 86

0.6350192 98

10906

3325

543 8

5238.4 6

9.589743 6

0.4986666 67

0.4803281 37

0.6535520 92

0.6352135 62

11014. 24

3358

549 2

5292.4 3

9.589743 6

0.4986666 67

0.4805083 55

0.6536722 37

0.6355139 25

11076. 56

3377

552 4

5323.5 1

9.589743 6

0.4986666 67

0.4806105 19

0.6537403 46

0.6356841 99

11076. 56

3377

497 7

4776.9 1

8.640758 54

0.4493194 44

0.4312632 97

0.6208421 98

0.6027860 51

11338. 96

3457

518 4

4984.2

8.792357 92

0.4572026 12

0.4395643 1

0.6263762 07

0.6087379 05

11765. 36

3587

558 1

5381.4 4

9.122993 31

0.4743956 52

0.4573965 97

0.6382643 98

0.6212653 43

12113. 04

3693

591 6

5716.1 9

9.392588 33

0.4884145 93

0.4719034 61

0.6479356 41

0.6314245 09

12372. 16

3772

617 2

5972.0 1

9.593512 9

0.4988626 71

0.4826973 45

0.6551315 63

0.6389662 37

12588. 64

3838

639 0

6189.8 9

9.761373 94

0.5075914 45

0.4917041 05

0.6611360 7

0.6452487 31

12673. 92

3864

647 7

6276.7 5

9.827501 02

0.5110300 53

0.4952496 16

0.6634997 44

0.6477193 07

12673. 92

3864

647 7

6276.7 5

9.827501 02

0.5110300 53

0.4952496 16

0.6634997 44

0.6477193 07

12719. 84

3878

652 4

6323.7 7

9.863107 9

0.5128816 11

0.4971581 43

0.6647720 95

0.6490486 27

12788. 72

3899

659 5

6394.6 2

9.916518 23

0.5156589 48

0.5000201 67

0.6666801 11

0.6510413 3

12896. 96

3932

670 7

6506.7 2

10.00044 88

0.5200233 36

0.5045158 05

0.6696772 03

0.6541696 73

13497. 2

4115

704 6

6846.1

10.03926 28

0.5220416 67

0.5072237 79

0.6714825 19

0.6566646 31

14694. 4

4480

704 6

6846.1

10.03926 28

0.5072237 79

0.6714825 19

0.6566646 31

0.6566646 31

LTOB M

Number Of Casing Strings Determination

From CSG Setting Depth Grap we Extract The Following Results Casing

Measure Depth, ft

Casing Length, ft

TVD

V. Length

Casing Bottom, ft

Casing Length, ft

13017.89

13017.89

From

To

4 1/2

13497.2

13684.16

186.96

7"

9748.16

13497.2

13497.2

9 5/8

0.00

9748.16

9748.16

9748.16

9748.16

13 3/8

0.00

3581.76

3581.76

3581.76

3581.76

30 " Conductor

0.00

75.6

75.6

75.6

75.6

367

i.

Casing Design When we design casing, it must be designed to withstand the maximum burst pressure, collapse pressure, and tensile forces that we anticipate that the casing will ever be exposed to. We then increase this by design factors. Casing is way over designed. Why? It will be exposed to hostile treatment from rotation of the drillstring inside it, pressures imposed on it from the inside and outside, and tension forces from changing internal pressures, external pressures, and changing temperatures during treatment and production. It will also be called upon to keep formation fluids in place long after in the well is plugged and abandoned.

 Casing Design for UBD drilling     

Casing design for UBD is not significantly different than conventional. With air drilling, the casing tension should always be design with no buoyancy considered. No difference in burst design – usually Collapse design should always be based on an empty casing string. A collapse design factor for UBD should be ~1.2 for UBD instead of 1.125 (API design factor).

 Steps of design The process of casing string design is divided into three stages:

368

1-

For collapse resistance:

2-

Checking for internal ( bursting ) pressure:

3-

for tensile strength ( upper part ):

4-

Checking for bending force:

First Casing Design According To Casing Availability In Badr Company

Design of 13 3/8 IN CSG:

pf max = pc min =

1954.9 psi 1998.902 psi

select grade K55

nominal wt pc selected L1 Casing

68 lb/ft 1950 psi 3581.76ft

Measure Depth, M

13 3/8

Casing Length, M

From

To

0

3581.76

3581.76

TVD

V. Length

Casing Bottom, M

Casing Length, M

3581.76

3581.76

γm, ppg

9.539797

Check  For tensile :

Section

Length, Ft

Depth ,Ft

N.Wt Ib/ft

Wt, Ib

Joint Strength , Ib

S.F

L1

3581.76

0 - 3581.76ft

68

243559.68

1069000

4.38906 8

 For Brust : GRADE

N.WT

P(I)

P(I)/Pf

case

K-55

68

3450

1.7647733

Safe

Design of 9 5/8 IN CSG: pf max = pc min =

369 4163.46 psi 3679.989 psi

select grade N-80 nominal wt pc selected L

47.1 lb/ft 7030 psi 9748.16 ft

Check

 For tensile :

ection

Length, Ft

Depth ,Ft

N.Wt Ib/ft

Wt, Ib

Joint Strength , Ib

S.F

L1

9748.16

09748.16

47.1

459138.34

1100000

2.3957

GRADE

N.WT

P(I)

P(I)/Pf

case

N-80

53.5

7930

1.9046658

Safe

 For Brust :

Design of 7

IN CSG:

pf max=

6846.100783 psi select grade N-80

nominal wt pc selected L

29 lb/ft 7030 psi 3749.04 ft

Check

Section

Length, Ft

Depth ,Ft

N.Wt Ib/ft

Wt, Ib

L1

13497.2

13497.29748.16

29

108722.16

Section

Length, Ft

Depth ,Ft

N.Wt Ib/ft

Wt, Ib

L1

13497.2

13497.2- 9748.16

29

108722.16

Joint Strength , Ib 676000

S.F

6.2176837

For tensile :

370


S.F

6.2176837

For Brust : GRADE N-80

N.WT 29

P(I) 8160

P(I)/Pf 1.1919194

case Safe

Final Report grade

Pc,psi

Wt, lb/ft

Length, ft

No.of joint

13 3/8''

K-55

1950

68

3570

85

9 5/8''

N-80

7030

53.5

9744

232

7''

N-80

3270

29

3738

89

4 1/5''

J-55

2270

20

84

2

casing

 Design Of 4 1/5 '' pipe : Choose High grade for Liner design because the collapse resistance is High at Bottom. Select grade J-55 or N-80, and is set at point @ 4172 m.  Design of conductor pipe: Choose low grade for conductor design because the collapse resistance is very low at surface. Select grade J-55 or H-40, and is set at the refusal point +/- 45m. The design must meet all design criteria and should do so at the lowest possible cost. All Casing grades weights of casing listed in the Halliburton Cementing Tables are available. The string may have multiple grades if that reduces cost.

371

Design of 13 3/8 IN CSG:

Available Grades: Grade

Weight, Ib/ft

Collapse,Psi

Tensile Strength,Ib

K-55

54.5

1130

636000

K-55

68

1950

1300000

L-80

72

2670

1693000

pf max = Pi =

1954.9 psi 1840.127209 psi

pc min = select grade L80

2070.143 psi

nominal wt pc selected L1 select grade K55

72 lb/ft 2670 psi 204.26308 ft

nominal wt pc selected L2 select grade K55

68 lb/ft 1950 psi 1420.2808 ft

nominal wt pc selected L3

54.5 lb/ft 1130 psi 1957.2162 ft

Check

 For Tensile :

372

Section

Grade

Length, Ft

N.Wt Ib/ft

Wt, Ib

14706.94


L1

L-80

204.263078

72

L2

k-55

1420.2808

L3

K-55

1957.2162

S.F

43.24489

68

96579.09

130000

1.346047

54.5

106668.3

1693000

15.87163

 For internal bursting pressure:

Grade L-80

Length, Ft 204.26308

N.Wt Ib/ft 72

L1

P(I)/Pf 3.0909

L2

k-55

1420.2808

68

3.21876

L3

K-55

1957.2162

54.5

1.76477

Check Above 1.1

Section

case Safe Safe Safe

Design of 9 5/8 IN CSG: Available Grades : Grade

Collapse,Psi

J-55 N-80

Weight, Ib/ft 40 47

2570 4750

Tensile Strength,Ib 630000 1086000

N-80

53.5

6620

1244000

pf max = Pi = pc min = select grade N-80 nominal wt pc selected L1 select grade N-80 nominal wt pc selected L2

4163.46 psi 4329.398831 psi 4870.574 psi 53.5 lb/ft 6620 psi 231.15323 ft

47 lb/ft 4750 psi 4367.8052 ft

select grade J-55 nominal wt pc selected L3

40 lb/ft 2570 psi 5149.2016 ft

373

Check

 For Tensile : Section

Grade

Length, Ft

N.Wt Ib/ft

Wt, Ib 10928.075


L1

N-80

204.26308

53.5

L2

N-80

1420.2808

L3

J-55

L3'

J-55

L4

N-80

113.8352

47

66753.196

1086000

15.99923

1957.2162

40

78288.647

630000

8.047143

3308.661

40

132346.44

630000

4.760233

1840.54

53.5

98468.89

1244000

12.6334

For internal bursting pressure: Grade N-80


N.Wt Ib/ft 53.5

L1

3.6876

L2

N-80

1420.2808

47

1.1998

L3

J-55

1957.2162

40

1.6335

L3' L4

J-55 N-80

3308.661 1840.54

40 53.5

1.1511 1.4454

Design of 7 IN CSG: Grade

Collapse,Psi

J-55

Weight, Ib/ft 24

1370

Tensile Strength,Ib 381000

H-40

24

2030

276000

N-80

29

7030

676000

Available Grades :

374

pf max = Pi = pc min =

6846.100783 psi 1949.5008 psi 2193.188 psi

P(I)/Pf

Check

Case Safe

Above 1.1

Section

Safe Safe Safe Safe

S.F

select grade N-80 nominal wt pc selected L1

29 lb/ft 7030 psi 275.24321 ft

select grade H-40 nominal wt pc selected L2

24 lb/ft 2030 psi 1129.4118 ft

select grade J-55 nominal wt pc selected L3

24 lb/ft 1370 psi 2344.385 ft

Check

For Tensile : Section

Grade

Length, Ft

N.Wt Ib/ft

Wt, Ib

7982.053 27105.88

Joint Strength , Ib 676000 276000

L1 L2

N-80 H-40

275.24321 1129.4118

29 24

L3

J-55

2344.385

24

S.F

84.68999 10.18229

56265.24

381000

6.77149

Check

Case

Section

Grade N-80


N.Wt Ib/ft 29

L1

P(I)/Pf 1.24132

L2

H-40

1129.4118

24

1.15455

L3

J-55

2344.385

24

1.13467

Above 1.1

For internal bursting pressure:

Safe Safe Safe

375

Final Casing Report : casing

grade

Pc,psi

Wt, lb/ft

Length, ft

No.of joint

13 3/8''

L-80

2670

72

204.263078

5

K-55

1950

68

1420.280757

34

K-55

1130

54.5

1957.216165

47

N-80

6620

53.5

204.263078

5

N-80

4750

47

1420.280757

34

J-55

2570

40

1957.216165

47

J-55

2570

40

3308.661

79

N-80

6620

53.5

1840.54

44

N-80

7030

29

275.24321

6

H-40

2030

24

1129.4118

27

J-55

1370

24

2344.385

56

J-55

2270

20

84

2

9 5/8''

7''

4 1/5''

376

CEMENT PROGRAM Cementing is one of the most important operation in drilling & producing a well Cement operation is a “one shot "process with no second chance , unlike mud is run as a dynamic continuously changing process Primary cementing is the initial step that seeks to seal the area between the casing and the drilled hole, completing the isolation needed for form a pressure vessel and appropriate barriers. Squeeze cementing is a technique to repair channels that may remain after the primary cement job

Purpose of Primary Cementing     

Provide zonal isolation, isolate porous formations Support axial load of casing st rings and strings to be run later Provide casing support and protection Support the borehole, whether drilling or completion Protecting the borehole in the event of problems 1. Pressure isolation 2. Pipe support and protection 3. Exterior corrosion 4. Pressure control 5. Load and force application support 6. Leakoff control – prevents crossflow?

Cement job

secondary

primary

one stage

Multi stage

Squeeze cement

377

 Primary cementing cost about 5% of well cost.  About 15% of primary cement jobs require squeezing  Total cost of cementing when squeezing is required is about 17% of well cost. Typical number of squeezes required to fix a problem in a primary cement job = 3.

nine types of API cement The American Petroleum Institute (API) has identified nine types of cement according to chemical composition and physical properties. These types range from standard construction cements to cements designed for use thousands of feet below the surface.

API classification and properties of oil well cement

378

Type

depth

Tempera ture F

Water Ratio Gal/sk

Slurry weight Ib/gal

Volum e 3 Ft /sk

Remarks

Class A

6000ft

60-170

5.2

15.6

1.18

Class B Class C

6000ft 6000ft

60-170 60-170

5.2 6.3

15.6 14.8

1.18 1.32

Class G

8000ft

200

5.0

15.8

1.15

Class H

8000ft 12000ft

200 200

4.3 5.2

16.4 15.6

1.06 1.18

may be used when no special properties are desired, no slufer resistance Moderate sulfer resistance Available in regular and high sulfer resistance Basic cement ,compatible with accelerators and retarders Basic cement higher density ,higher and lower water volume

 Class A • Depth surface – 6000 ft (1830 m) • No special properties • Similar to ASTM C 150,Type I  Class B • Depth surface – 6000 ft (1830 m) • Moderate to high sulphate resistance • Similar to ASTM C 150 Types II  Class C • Depth surface – 6000 ft (1830 m) • High early strength • Moderate to high sulphate resistance  Class D • Depth from 6000 ft – 10,000 ft (1830 m - 3050 m) • Moderate and high sulphate resistance • Moderately high pressure and temperature  Class E • Depth from 10,000 ft – 14,000 ft (3050 m - 4270 m) • Moderate and high sulphate resistance • High pressure and temperature  Class F • Depth from 10,000 ft – 16,000 ft (3050 m - 4270 m) • Moderate to high sulphate resistance • Extremely high pressure and temperature  Class G • Moderate to high sulphate resistance • No addition other than calcium sulphate or water  Class H • Depth surface – 8000 ft. (2440 m), as basic cement, course • Can be used with accelerators and retarders for other Specifications • Moderate to high sulphate resistance  Class J * Depth 12,000 – 16,000 ft. (3660 m - 4880 m) * Extremely high pressure and temperature * Can be used with accelerators and retarders for other

379

****Methods of cementing:

It is normally to cement conductor and surface pipes .A single batch of cement is prepared and pumped down the casing .It should be noted that all The internal parts of the casing tools including the float shoe, wipe plugs, etc are easily drillable.

It is employed in cementing long casing string in order to reduce the total pumping pressure, reduce the total hydrostatic Pressure on weak formations There preventing Their fracture, allow of selective cementing of formations and ensure effective Cementing around the shoe of the previous casing string In multistage cementing a stage cementer is installed at a selected position in the casing string, the position of the stage cementer is dictated by the total length of the cement column and the strength of formations.

The liner is a short string of casing, which does not reach to the surface .It is hung from the bottom of the previous casing string by use of a liner hanger. The liner is run on drill pipe and cemented by pumping the cement slurry through the drill pipe and liner and finally displacing it behind the liner to Just above the liner hanger.

380

CASING AND CEMENT HARDWEWRE

Component

Description

Guide Shoe

*Run on the bottom of the casing *Used to guide the casing into the hole *Hollow center allows mud to flow into casing when run in hole

photo

Generally placed 1 - 2 joints above the shoe to 80 ft [13 to 26 m]

Float Collars

centralizes

scratchers

Centralize the casing inside the hole

Used to remove mud cake from the borehole wall

381

This is a solid plug used to clean and

Bottom plug

separate between cement and mud or dispersant

Description

Top plug

382

The black top plug has a deep cup on its top and has a solid, molded rubber core. It is dropped after the cement slurry has been pumped, to prevent contamination with the displacement fluid.

Chemical Washes

Chemical washes are fluids containing surfactants and mud thinners, designed to thin and disperse the drilling fluid so that it can be removed from the casing and borehole. Washes are available for water-based and oilbased drilling fluids. They are designed to be used in turbulent flow conditions.

Spacers

Spacers are fluids of controlled viscosity, density and gel strength used to form a buffer between the cement and drilling fluid. They also help in the removal of drilling flui during cementing.

<< Cement Program >> * Casings setting depths: Casing

Measure Depth, m From

To

13 3/8"

0

1092

9 5/8"

0

7" 4.5"

Casing Length,m

Casing ID"

Casing OD"

1092

13.375

12.415

2792

2792

9.625

8.861

2817

4115

1298

7

6.184

3407

4171

764

4.5

4.09

 Cement of class "G" was used for well cementing as a result of its properties for this high depth and salinity resistance

383

 Annular area between casing string and bore-hole (

)

D :Hole diameter, in :Casing outside diameter, in  Slurry volume V

Excess :Safety factor, 60 %of the slurry volume

 Slurry volume :V, is the number cubic feet of slurry that produced from one sack of dry cement, The thickening time of a cement slurry is the time during which the cement slurry can be pumped and displaced into the annulus (i.e. the slurry is pumpable during this time). The slurry should have sufficient thickening time to allow it to be: • Mixed • Pumped into the casing • Displaced by drilling fluid until it is in the required place

384

Because the surface casing is set at depth of 1092m the cement class that will be used is (class G)that intended to be used at depth in range of 1000- to 8000 ft in conditions that require moderate strength, temperature, and pressure with the ability of adding additives or can be used a manufactured Properties of cement component

Weight Lb

Specific gravity

Density Lb/gal

Volume Gal

Dry cement

94

3.14

3.14 × 8.34

3.5938

2 %bentonite

1.88

2.65

2.65 × 8.34

0.0852

Mix water for cement 44% Mix water for bentonite 10%

41.36

1

1 × 8.34

4.9652

9.4

1

1 × 8.34

1.12845

385

386

387

388

389

Properties of Foamed Cement  Will the strength be adequate and will the sheath be destroyed by perforating?  Compressive strength of foamed cement is generally higher than a comparable nonfoamed cement of the same density.  Will there be gas migration through the cement itself?  Will the bond be different than for conventional cements?  Cement companies have additive in which the HSP of the cement can be reduced.  Example is hollow glass micro spheres. Design Considerations  Foam quality.  PVT behavior.  Cement system.  Free water.  permeability.  Compressive strength.  Fluid Loss.

Lightweight Additives Sometimes, a slurry weight needs to be reduced to protect formations that have a low fracture gradient or for economics. To reduce the weight of cement slurries, you can add water, low specific-gravity solids, or foam cement.

390

Foamed cements are also used to reduce the density of the slurry In foamed cement, nitrogen is added to the cement mixture .Very low densities can be obtained with foamed cement but they are more expensive.

Bentonite is the most common light weight additive * Bentonite will tie up extra mix water reducing density

* Light weight, filler cements have as much as 12% Bentonite –

Adding Bentonite thickens the cement slurry

and it must be thinned by adding a thinner or friction reducer

    

Cement companies have additive in which the HSP of the cement can be reduced. Example is hollow glass micro spheres. Lightweight additives or extenders are used to decrease the density of cement Excess mix water can be used to decrease the density to a limited extent Excess water increases thickening time, increases free water and reduces compressive strength

391

DESIGN OF HORIZONTAL TRAJECTORY 1) Vertical section: It is drilled from seabed (mud line) until kick-off point (KOP). 2) Turning or curved or angle build section: It is drilled from kick-off point (KOP) to the end-of-curve (EOC). This section includes the first build arc, the straight tangent, and the second build arc.

3) Tangent section: It is drilled from the end of second build arc (EOC) to the end of proposed distance to be drilled horizontally in the pay zone, in accordance with the type of horizontal well to be drilled.

FIGURE 5: HORIZONTAL TRAJECTORY PLAN

392

The three sections may be designed as follows:  The build radius of the build arc: R = 5730/Β  The height of the first-build arc: D1 = R (Sin I2 - Sin I1)  The height of the straight tangent: D2 = L2 Cos I2  The height of the second-build arc: D3 = R (Sin I3 - Sin I2)  The length of the first section of horizontal well KOP: KOP = TVD –( D1 + D2 + D3)  The displacement of the first-build arc: H1 = R (Cos I1 - Cos I2)  The displacement of the straight tangent: H2 = L2 Sin I2  The displacement of the second-build arc: H3 = R (Cos I2 - Cos I3)  The length of the first-build arc: L1 = 100 (I2 - I1) / BUR  The length of the second-build arc: L3 = 100 (I3 – I2) / BUR  The measured depth at the end of the first-build arc: MD1 = KOP + L1

393

 The measured depth at the end of straight tangent: MD2 = MD1 + L2  The measured depth at the end of the first-build arc: MD1 = MD2 + L3  The length of the horizontal section or third section = H This length is selected according to the turning radius of the horizontal well to be proposed

394

Design Of Horizontal Trajectory For Obaiyed-D2  Well information data Well Name Country // Area

D-2 A. Horizontal Development Gas / Condensate well Egypt // Western Desert

Concession // Field

Obayied

Operator

Badr Petroleum Co.

Drilling Unit

EDC, Rig-41

Ground Elev.// RKB Elev.

203.77 m // 213.87 m

Surface Co-ordinates

Y = 323756 m N

& X = 659394 E m

Target Co-ordinates

Y = 323901 mN

& X = 658826 Em

Target Name

Khatatba formation (Lower Safa Sandstone Reservoir) 6” Build & Lateral section

Key Points K.O.P Depth, m MD, (m TVD)

3460

BUR, O/30 m

2-3

Azimuth, Degrees

279

Maximum inclination

90

Maximum Dog-Leg Severity

2-3

End of Build, m MD, (m TVD)

4257 (3968.87)

Landing Point Co-Ordinates (Heel)

Y = 323866 m N

Landing Pont m MD, m TVDBDF

4257 (3968.87)

Lateral Section Length, m

150 m (if required)

TD, m MD, (m TVD)

4407 (3968.87)

Target Tolerance

Circle with radius 50 m long.

Static Temp. Gradient

1.54 OF/100 ft

Offset wells

Obayied JB 16-3 and D2 original hole

X = 658895 E

395

Actual trajectory design

396

MD (m)

MD (ft)

Inc.

Azimuth

TVD(ft)

TVD (m)

DLS /30m

HD

0

0

0

0

0

0

0

0

1000

3280

0

0

3280

1000

0

0

2000

6560

0

0

6560

2000

0

0

3000

9840

0

0

9840

3000

0

0

3480

11414.4

0

0

11414.4

3480

0

0

3510

11512.8

3.5

30

11512.8

3510

3.5

0

3994

13100.32

60

30

12809.38

3905.3

3.5

88.7

4020

13185.6

60

30

12851.7

3918.2

0

101.8

4050

13284

64

30

12897.62

3932.2

4

117.8

4193

13753.04

83

30

13029.8

3972.5

4

220.5

4200

13776

83

30

13033.08

3973.5

0

226.5

4480

14694.4

83

30

13144.6

4007.5

0

472.5

4500

14760

85

30

13151.82

4009.7

3

490.3

4530

14858.4

88

30

13157.39

4011.4

3

518.6

5200

17056

88

30

13234.47

4034.9

0

1165.1

397 FIGURE 6: A CTUAL TRAJECTORY

Horizontal trajectory design: Input Data

 Surface coordinates N m

323755.8

Em

659393.8

Nm

323901.6

Em

658826.1

 Target Coordinates

 Landing Point Coordinates

398

Nm

323866

Em

658895

Total Vertical Depth (TVD)

3968.87

m

I2

24

degree

L2

150

m

I1

0

degree

I3

87

degree

Calculations All the calculated data are expressed in meters (m) Calculations Displacement @ landing point

486.4745

Raduis of curvature R1

448.9608

Build Up rate

12.76281

the height of the first build arc D1

182.6088

height of the straight tangent

61.0105

height of the second build arc

265.7367

KOP

3459.514

displacement of the first build arc (H1)

38.8147

displacement of the straight tangent (H2)

61.0105

displacement of the second build arc (H3)

386.6493

length of the first arc L1

626.8213

length of the second arc L3

34.49998

measured depth at the end of the first arc

4086.335

measured depth at the end of straight tangent

4236.335

measured depth at the end of the second arc

4270.835

length of the horizontal section=

633

total horizontal measured depth=

4903.8

399

400

FIGURE 7: PLANNED WELL TRAJECTORY

FIGURE 8: COORDINATE EASTING AND NORTING

FIGURE 9: A CTUAL VS PLANNED

401

402

FIGURE 10: OBAIYED D2 DIRECTIONAL PLANNING USING COMPASS TM

Dog leg severity Dogleg severity is a measure of the amount of change in the inclination, and/or azimuth of a borehole, usually expressed in degrees per 100 feet of course length. In the metric system, it is usually expressed in degrees per 30 meters or degrees per 10 meters of course length. All directional wells have changes in the wellbore course and, therefore, have some dogleg severity. If not, it would not be a directional well. The dogleg severity is low if the changes in inclination and/or azimuth are small or occur over a long interval of course length. The dogleg severity is high when the inclination and/or azimuth changes quickly or occur over a short interval of course length.

The dog leg severity can be calculated from the dog log angle as follow; I  2  A   sin   sin I 1 sin I 2 `  2   2 

  2 sin 1 sin 2 

Where:   

β=dog leg Angle ΔI= the change in inclination ΔA= the change in Azimuth

The dog leg severity then expressed as;

 100    MD 

  Where: δ= Dog leg severity (DLS)

ΔMD= change in the measured depth

403

From the deviation plot, we can conclude the following table:

MD

I

A

1

4086.335

0

284

2

4236.335

24

292.5

3

4270.835

87

334

ΔMD1=150 The course length over which the change in inclination (m) ΔMD2=34.5 ΔI1 =24 Change in the inclination ΔI2= 63 A1=8.5 Change in Azimuth A2=41.5

 100   24   8.5  1 o sin 2    sin 2    2 sin  sin(0) sin(24)  0.0003 / 100'  150 * 3.28   2   2 

 

 100   63   41.5  1 o sin 2    sin 2    2 sin  sin(24) sin(87)  0.122 / 100'  34.5 * 3.28   2  2 

 

At all times high doglegs should be avoided (DLS < 6 deg/100ft) in order to reach the total depth required, minimize torque and preventing sinusoidal / helical buckling of the slim drill string.

404

Operations (Drilling Sidetrack 6 ” hole) Objective 1. To ensure availability of some 10MM scf/d to allow a DCQ of 300 MMscf/d 2. To prepare the well for possible later coiled tubing under balance drilling Formations to be drilled (3460 – 4407 m AHBDF)  Masajid  Khatatba  Lower Safa. TD at 4407 m” Potential Problems  High drilling torque and drill string failures  Casing wear in doglegs  Low ROP  Drill string stuck  Losses due to fracture in horizontal section

Mud type LTOBM with CA CO3

Density 0.46 - 0.48psi/ft

The use of LTOBM in this section eliminates the hole problems during the 6” hole drilling and minimum mud weight required to drill the reservoir section, based on RFT pressures in offset wells for upper safa formation is Hydrostatic plus the formation is tight and lower safa formation is is 0.42 psi/ft. To balance between ROP and borehole stability in the 6” hole section, we intend to start drilling the section with 0.46 or 0.48 psi/ft mud and may be gradually raise it in stages to 0.49 psi/ft in case of shale caving from Khatatba formation or high gas reading

405

Operational Sequence 1.

Run 6 .059 “ gauge ring to depth +/-3480 m

2.

M/up & RIH 7“ bridge plug on drill pipe to +/-3461m and set same (avoid to set it against casing collar)

3.

P/U & M//U 7” Trip Saver WhipStock (Remember: while checking the alignment with the MWD, the whipstock was dropped).

4.

RIH w/ the whipstock and tag the bridge plug.

5.

RIH w/ gyro and orient the whipstock in direction of 279 deg

6.

Set the Whipstock at +/-3460 m @ 279 azimuth and mill 7 “ window as per operator recommendation and attached running procedures. - If the melon mill is damaged or under gauge once retrieved. M/up a new milling assembly and clean (smoothen) the window.

7.

M/U directional assembly with 1.15 deg bent housing, RIH and displace the well to LTOBM mud system. Mud weight of 0.46 psi/ft will be used to start the section. Whilst drilling, the mud weight will be raised in stages to 0.48 psi/ft if required .

Recommended drilling assemblies:

Note : to decrease chance of stuck we are recommend to use Enhanced drill pipe just after sidetrack to decrease the contact point of BHA and minimize no of D/C in BHA Kick Off: 6“ Tri cone Bit - Motor W/ 1.15 bent housing – MWD – 4 ¾ D/C’s – Jar - 2 D/C – 30 HWDP

406

8.

Kick off as plan. Drill 5m of new formation. Condition mud and perform a casing integrity test to 0.65 psi/ft. Continue kick off to end of build up section or until the bit has been dulled. POOH.( LWD tool to be consider through Lower Safa formation ), need to use the tandem pill to clean the hole to avoid the cutting bed

9.

In the horizontal section of the well, the use of a turbine with impregnated bit will be considered.

10.

Drill ahead to TD. The TD is defined in directional programme as 4407m ahbdf.

11.

When at TD, sweep the hole clean (150%) with viscous mud. Spot 50 bbls of hi-vis pill at bottom. POH and rack BHA.

12.

Log well as per logging programme (separate issue)

13.

Make wiper trip after the logging programme (if required).  Prepare to run liner while logging. The combination liner hanger tie Back

    



 

packer and float equipment is NVAM connections. Hence have sufficient spare NVAM couplings to Bakerlock the shoe track (although not planned to be drilled out - the liner could get stuck way off bottom!). Prepare the shoe track on the pipe racks to save time. No X-overs will be necessary for below the hanger, again onto the shoe track and to/from the Super 13% Cr which has N.Vam. The rest of the liner has N.Vam, connections. This well requires all 4 ½” liner will be Super 13% Cr liner. Two short pup joints are required as a marker at top and bottom of Lower Safa payzone. The exact depths shall be confirmed after TD logging. The 4 1/2” combination liner will be run with a 100 m liner lap into the 7” liner. If hole condition is good during the previous trip and while logging, no wipertrip is necessary after logging. Wiper-trip only if hole condition dictates. Perform the liner cement job with a 30 m shoe track between float shoe and landing collar. Use a batch mix tank to ensure a high quality and homogenous tail slurry; flush lines before releasing pump down plug. Cement spacers for the mud cake removal will be advised (ensure sufficient spacer is used behind plug to avoid cement/mud interface when pulling back into planned excess cement above TOL). Critical during this cementation is ECD which needs to be below the frac gradient of the Shiffah sands (0.60 psi/ft). Have 3 ½ ” drillpipe pup joints on site for space out of the liner. In an attempt to improve the quality of the cementation solid type centralizers shall be used.

14.

Run 4 ½ ” liner & tie back packer S 13 % chrome, p110 with a 100 m overlap inside 7 ” casing,

15.

Cement 4 ½ ” liner as per separate program.

407

References: 1- Farahat, M.S., “ Horizontal well drilling technology “, Suez Canal University, Faculty of Petroleum & Mining Eng. 2- Bourgoyne, A. T., “ Applied drilling engineering “, Society of Petroleum engineers Rechardson, TX 1991. 3- Economides, M. J., “ Petroleum well construction “, John wiley & Sons, 1998. 4- Gatlin C., “ Petroleum engineering “, Department of Petroleum engineering, University of Texas, 1960. 5- Rabia, L., “ Oil well drilling engineering “, John Wiley & Sons, 1998. 6- Rotary drilling data handbook. 7- N. J. Adams, “ Complete Well Planning Approach “.

408

410

`

For Underbalanced Drilling operation .

This chapter introduces the main principle for risk assessment in drilling underbalanced well. The risk assessment forms an integral part of the underbalanced selection process and ensuring that operators are made aware of the potential risks, the risk assessment is carried out during the candidate selection process.

Contents: 1. Introduction of risk assessment 2-Risk Assessment

3-Risk Management and Downhole Problem 4- Health Safety and Environment 5- Personal Protective Equipment (PPE)

Focus on the TRAp ….. Not the chess! 411

Introduction of risk assessment It is a requirement of legislation, and also good company practice and common sense, that all work tasks should be subject to an assessment of their risks. This is in order to identify the hazards present, assess the risks involved, and identify the controls and precautions necessary to undertake the work safely. This part of the document shows how TRA fits into the work management process by describing the generic methodology that is followed when work is to be undertaken. The main steps are illustrated figure and in more detail in the inside cover. When a task is identified, the first action is to establish what it will involve. This initial appraisal should identify the need for any special safety studies or assessments and identify at the outset if it is clearly obvious that the task cannot be carried out safely. If the likely hazards cannot be reconciled at this stage, then the task should be rejected or redefined. The next stage represents the heart of the TRA process. It involves identifying the hazards associated with the task, assessing the risks and identifying the controls/precautions required to mitigate those risks. Where a task comprises a number of separate activities, these should be broken down into individual tasks and assessed separately. The extent of the controls identified will depend upon the level of risk associated with the task. The higher the risk, the greater the degree of control.

Risk Assessment The risk assessment forms an integral part of the underbalanced selection process and ensuring that operators are made aware of the potential risks, the risk assessment is carried out during the candidate selection process. The IADC well Classification form an essential fist step in the overall risk assessment. The IADC classification for underbalanced wells should be assigned to every well drilled underbalanced. This gives the first indication of the potential risks. The next step in the risk assessment is the review of the reservoir and the produced Fluids

412

The risk assessment for the reservoir reviews the kind of fluids that are expected, the gas rates and the production profile. It also reviews if any H2S is being produced and of course it looks at the depth of the reservoir and the pressure in the reservoir.

`

A deep high-pressure sour gas reservoir would obviously have a classification with higher risk compared to a low-pressure oil producer. The reasons and objectives for underbalanced drilling are also very much a part of the risk assessment. A well drilled underbalanced to minimize skin damage will need to be maintained underbalanced at all times, thus adding complexity to the operation. As part of the QHSE section of the risk assessment, the equipment required and fluid systems to be used are also recorded as is the number of people on location and the experience of the rig crew The tripping method in an underbalanced drilled well is crucial. Avoiding pipe light and snubbing can reduce the risk level significantly. Finally the experience of the operator is taken into account together with a look at how the job will be performed.

Risk Management and Downhole Problems 

Risk Management   



Risk Identification Quantitative Risk Analysis Risk Mitigation Planning

Downhole Problems and Troubleshooting     

Wellbore Instability Excessive Vibration Fluid Influxes Stuck Pipe and Fishing Corrosion

Risk Management Introduction 

A major success factor in UBD is how effectively the designers and implementers identify risks and develop an effective plan to deal with the risks.



Before implementing the final design, the selected equipment and operating procedures should be subjected to an exacting risk analysis

413

Stages Risk Identification

Quantitative Risk Analysis

Risk Mitigation Planning

Risk Response

FIGURE 1: MAIN STAGES OF RISK MANAGEMENT

Risk Identification      

Source of Risk. Probability of Occurrence. Potential Impact. Action to Mitigate. Cost to Mitigate. Probability Mitigation Succeeds.

Source of Risk  

Internal: External:

risks that the designer can control. risks that the designer cannot control.

Probability of Occurrence Can be on a scale of:  

1 to 10 or High, Medium, and Low

Potential Impact   

414



High, Medium, or Low. May be referred to as “Consequence” Can be defined by dollar amounts or other criteria, such as severity of injuries or death, or any combination of dollar amount and injury. Probability * Consequence = Risk

`

Personal Protective Equipment (PPE) The safety of personnel on any oil and gas operating location is of primary concern to all of the companies involved. The supply and use of appropriate PPE is one of the tools used to make the work environment a safer place. The basic PPE set includes coveralls, hard hat, steel toed boots, and safety glasses. In addition, some tasks conducted on the work site may require the use of specific PPE.

FIGURE 2: PERSONLA PROTECTIVE EQUIPMENT (PPE)

UBO Hazards and PPE Requirements. An underbalanced drilling operation is basically a concurrent operation involving conventional drilling equipment; equipment normally associated with well testing; equipment normally associated with well stimulation work and all combined with the sights and sounds of a production operation. The personnel that work in these disciplines are quite familiar with the PPE requirements for their work. For an UBO, we need to make others recognise hazards that may not normally be associated with their disciplines and ensure the appropriate PPE is available and is used. Natural gas – Leaking gas is a potential source for a flash fire or explosion. Crews working around the natural gas compressors and gas separation equipment should wear fire retardant coveralls.

415

Noise – Hearing protection is required when working or passing through an area with a noise level greater than 85dB. An underbalanced drilling operation will have more noisy areas associated with it than a conventional one. Compressors, flaring operations, high flow rates of gas through small piping and additional pumps are the primary ones to consider. These areas must be identified and well signed that hearing protection is required. Radio headsets for communication will be also required. Figure 6 shows the universally accepted graphic symbol for “hearing protection required” as well as written requirement in English and Arabic Formation fluid storage – Hydrocarbon storage and associated hazards have already been discussed. However, produced water can also contain toxic products. Sour produced water will release H2S vapors and therefore must be handled accordingly. The use of wind direction indicators (wind socks) on the tanks is recommended and the storage area must be treated as a controlled entry area. Personnel expected to work in the area must be trained in the use of personal breathing air equipment. Breathing air equipment (cascade system) and respirators must be available in a designated safe zone close to the storage tanks. The Rules of Conduct must be clear to all and all personnel on location must know the location of safety equipment. Flare by-products – SO2 is a by-product of the flaring process. It is extremely toxic to living organisms. The area around a flare stack must be treated as a hazardous area. The use of wind direction indicators (wind socks) at ground level is recommended. Because of the heat generated, workers may want to hang around the base of the stack during coffee breaks especially in colder climates. This is not allowed and must be discouraged.

Environmental Aspects The underbalanced drilling system is a fully enclosed system. When combined with a cuttings injection system and an enclosed mud pit system, a sour reservoir can be safely drilled using an underbalanced drilling system. The pressures and flow rates are kept as low as possible. It is not the intention to drill a reservoir and produce it to its maximum capacity. A well test can be carried out during underbalanced drilling to provide some productivity information. The hydrocarbons produced during the UBD process can be routed to the platform process plant, exported or flared.

416

There is work currently being undertaken to reduce flaring and recover the hydrocarbons for export. In a prolific well, a significant amount of gas can be flared during the drilling process. Recovering this gas provides an environmental benefit and an economic benefit. Oil and condensate recovered are normally exported via stock tank into the process train.

`

Safety Aspects Besides the full HAZOP, a significant amount of crew training is required for underbalanced drilling. A drilling crew has been instructed during its entire career that if a well kicks it must be shut in and killed. During underbalanced drilling, the single item to be avoided is to kill the well. This may undo all the benefits of underbalanced drilling. Working on a live well is not a normal operation for a drilling crew and good training is required to ensure that accidents are avoided. The underbalanced drilling process is more complex when compared to conventional drilling operations. Gas injection, surface separation, and snubbing maybe required on a well. If the hydrocarbons produced are then pumped into the process train, it is clear that drilling is no longer a stand-alone operation. The reservoir is the driving force in the UBD process. The driller must understand the process and all the interaction required between the reservoir, the liquid pump rate, the gas injection and the separation process system to safely drill the well. When tripping operations start, the well must remain under control. Snubbing pipe in and out of the hole is not a routine operation, and a specialized snubbing crew is normally brought on to snub the pipe in and out of the hole. The extra equipment also brings a number of extra crew to the rig. So besides a more complex operation, a number of service hands are on the rigs that now need to start working with the drilling crew. Yet the drilling crew will move back to conventional drilling once the well is completed. The drilling crew will need to be trained in this change of operating. If a number of wells are to be drilled underbalanced in a field, it may be an option to consider batch drilling of the reservoir sections. This saves mobilization and it also sets a routine with the drilling crew.




417

CONCLUSIONS AND RECOMMENDATIONS CONCLUSIONS This project was conducted to provide a literature review in candidate selection of underbalanced drilling techniques and build a design system to achieve proper planning for UBD operation.

UBD is being accomplished using a number of different techniques. The techniques are defined by the wellbore objectives and the fluid to be used in the operation. These include aerated (or gasified) fluid operations, foam operations, mist operations, and air (or gas) operations. Aerated (or gasified) fluid operation was fully described in our case study.

Gasified liquids can be used to achieve underbalance conditions, and damage will result primarily when making connections, tripping, logging, choking and completing the well.

A discussion of the economics of underbalanced drilling technology was presented. It showed that UBD can be cost effective, when proper planning and design of the UBD operation are utilized.

The key to success in applying underbalanced drilling lies in a good understanding of the technology, careful planning (including full consideration of the risks), disciplined execution, and effective dissemination of technological information. This thesis presents the development of an UBD operation design system for deciding whether to drill underbalanced or overbalanced, and for making a preliminary selection of adequate UBD fluids..

Design level consists of three models:  



Circulation rate program which determines the optimal circulation rate for the selected technique to guarantee adequate hole cleaning, to ensure vertical transport of cuttings in annular zones. Pressure calculation model, which assures that the selected technique, is the optimal selection, where the bottomhole pressure will be within the safe operation limits during the UBD operation. Economic study model, which assures that the sel ected technique, is the optimal selection in term of economic benefits.

419

RECOMMENDATIONS Real time field data is needed for different scenarios to guarantee that the system is capable to be applied for field uses.

Technology is advancing rapidly. While this work focuses on predictive models for design and supervision purposes, there are always opportunities to improve the models for better calculation accuracy. In our case study, it was recommended to consider a foam CTUBD scenario to eliminate the corrosion action take place and minimize the formation damage. Changing the circulation technique should be also take into account in order to obtain a correct reading of MWD/LWD equipment.

Future development in measurements while drilling (MWD) and telecommunications technologies will make it possible to tune the models in a close loop and optimize UBD hydraulics data from real time measurements.

Recent improvement in UBD technology such as the use of coiled tubing , parasite string ,concentric string and non-mud pulsed electromagnetic measurement while drilling have been useful in reducing the periodic overbalanced pressure phases occurring during some drilling operation and that is what has to be considered from the first planning of drilling Obaiyed D2 field

420

مشروع التخرج Underbalanced Drilling - Copy

Recommend Documents