COPYRIGHTcloud1.activelearner.com/contentcloud/portals/...From exploration and appraisal into field development, the use of mobile offshore drilling rigs moves to permanent drilling

Onshore and Offshore Drilling and Programs

Overview

In the exploration and appraisal phase of the life cycle, exploration wells are drilled to confirm the presence of hydrocarbons and estimate the recoverable reserves.

Once the field development plan has been established, a number of wells will be predrilled as part of the development program. These wells will then be completed as production wells as the field is brought onto full-scale production. As the field is produced, each of the wells drilled will be utilized as appropriate for production, injection wells, pressure maintenance, and observation wells over the life of the field.

Drilling objectives are to safely, economically, and in a timely manner, complete and deliver a well that meets requirements and design elements specified in the well plan. The well requirements and design elements will change across the exploration and production life cycle. We will review the different systems and components of drilling a well to the objectives of the well design, whether onshore or offshore.

In this module, you will learn about: Well function. Drilling history. Onshore drilling. Offshore drilling. Drilling program.

Drilling Operations and Well Completions Core ═════════════════════════════════════════════════════════════════════════

© PetroSkills, LLC. All rights reserved._____________________________________________________________________________________________

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Drilling History: Ancient to Modern

Asia 256 BCE• Spring Pole Drilling

• Discontinuous, Bailer

• Casing, Pipelines - Bamboo

• Max Depth 3,000 Feet (914 m)

• Drill Rate - 200 ft (61 m)/year

Europe 18th Century• Cable Tool Drilling

• Steam MechanizedProcess

• Discontinuous,Bailer

• Casing, Pipelines -MetalWith

tools asshownin hole

Rope Stirrup

Tools

Fulcrum

Heavy boulder

Drawing byS.T. Pees and

Associates

Rotary Drilling• 1st Oil Well at Spindletop

• Rotary Rock Bit - Hughes Tool Company 1901

Mud Motor Drilling• Positive Displacement Motor

(1970s)

Drilling History: Turn-of-the-20th Century



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Onshore Drilling

Drilling operations in the modern era began onshore, and today, the majority of drilling rigs on a global basis operate onshore. This diagram shows the component parts of an onshore drilling rig, including the drilling mast, or derrick, rig floor, and blowout preventers (BOP) in the cellar as well as the required mud pumps and shale shaker that are part of the fluid circulation system.

The type of rig used is determined by the drilling depth required to reach the formation of interest. The rig chart shows a typical rig and depth definition classification.

Rig Size Drilling Depth

Light Duty 3,000–5,000 feet

[1000–1500 meters]

Medium Duty 4,000–10,000 feet

[1200–3000 meters]

Heavy Duty 12,000–16,000 feet [3500–5000 meters]

Very Heavy Duty 18,000–25,000+ feet[5500–7500+ meters]



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Onshore Drilling

Pad Drilling

In the United States and Canada, pad drilling has become the norm. Pad drilling is where a series of horizontal wells are drilled into the formation of interest (typically shale reservoirs) from a single point, then drilled directionally out from that point, and moved to the horizontal trajectory to produce the reservoir.

In each case, whether drilling a vertical well, deviated well, or horizontal well, the wellbore constructed is designed by the drilling engineer to meet the objectives of the exploration or production departments.



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Offshore Drilling

Offshore drilling has the same objectives as onshore drilling: reach the target formation safely, on time, and in the most economic manner. The additional challenge is how to get from the surface of the sea, lake, or marsh, through the water, and then to begin drilling in the rocks that exist below the seafloor or lake bed. This is accomplished in the exploration and development phase by using mobile rigs.

Mobile rigs are either bottom-supported or not bottom-supported. A jack up is bottom-supported, and operates in shallow water. The support legs actually sit on the lake bed or sea floor. In deeper waters, semis or drill ships are used. Semisubmersible rigs and drill ships float on the sea and are not bottom-supported, hence the term “floaters”.

The offshore drilling rig connects to the seafloor from the rig floor using a “riser”. A drill ship can operate in deeper water than the semisubmersible. Semis and drill ships operate not only in shallow water, but also in the Deepwater and ultra-Deepwater. Collectively, semis, drill ships, and jack ups are referred to as MODUs – "mobile offshore drilling units”. In all respects, the components of the drilling rig structure above the water level are very similar to those on an onshore drilling rig.

Semi-submersible “Semi” Deepwater: Anchored > 8,000 feet (2,438 m) Dynamically Positioned > 10,000 ft (3,048 m)

Drillship Dynamically Positioned Deepwater > 10,000 ft (3,048 m)



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Offshore Drilling and Production Platforms

From exploration and appraisal into field development, the use of mobile offshore drilling rigs moves to permanent drilling and production platforms. The type of platform used is determined by the water depth in which the production will take place. In the Gulf of Mexico, the North Sea, and many parts of the world, the fixed platform is commonly used.

As production expands into deeper and deeper water, innovative designs allow drilling and production from a fixed location. These include SPAR and TLP platforms.

Designed water depths for offshore drilling and production systems:

Fixed Platform – 1,650 feet (500 meters)

Compliant Tower – 3,000 feet (915 meters)

TLP (Tension Leg Platform) – 6,000 feet (1,830 meters)

Semi Floating Production System – 8,000 feet (2,450 meters)

Spar (Classic, Truss, Cell) – 10,000 feet (3,050 meters)

Control Buoy – 10,000 feet (3,050 meters)

FPSO (Floating Production Storage Offloading) – 7,500 feet (2,290 meters)



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Drilling and Production Platforms

During production, wells drilled fromsingle surface location

• Onshore pad drilling (below)

• Offshore platform drilling (right)

Scale sketchof riser

Offshore Drilling

Marine Riser



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Offshore Drilling

Drill Ship Semi-submersible

Drill Ships and Semi-submersibles

Drill ships and semisubmersibles must be positioned over the drill hole

This is achieved in one of two ways:• The vessel can be anchored over the drill hole

• In deeper water, we see the use of dynamic positioning



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Horizontal Wells

Horizontal drilling is a method of drilling that exposes more reservoir rock to the wellbore surface than is possible by drilling a conventional vertical well through the target formation.

Because most oil and gas reservoirs a have greater areal (horizontal) range than vertical (thickness), drilling a well that can intersect and run through that horizontal plane produces greater volumes of oil and gas, due to the larger wellbore surface area within the producing interval.

Objectives for horizontal drilling are related to specific physical characteristics of the reservoir, such as:

Avoiding water production and gas influxes. Better reservoir pressure maintenance. Boosting the recovery factor of mature fields.

Horizontal drilling often has a higher overall cost per foot/meter; offset by increased production rates.



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Horizontal Well Drilling

Horizontal well drilling starts as a vertical or deviated well that extends from the surface down to a pre-determined "kickoff point", where it is then turned to the horizontal to intersect the reservoir. At this point, it continues horizontally within the reservoir to the desired location.

The initial vertical section is drilled conventionally, and depending on the curvature or bend and hole diameter, the deviated portion may be drilled either conventionally using a mud motor mounted directly above the bit in the BHA. The horizontal portion is drilled using a downhole motor.

Horizontal wells are generally classified by the arc radius as the wellbore curves from vertical to horizontal:

Short radius – 3 to 40 feet (~1 to 12 meters) Medium radius – 200 to 1,000 feet (~60 to 305 meters) Large radius – 1,000 to 2,500 feet (300 to 760 meters)

Recompletions of existing wells most often use short or medium radii; while most new wells are drilled with longer radii. Longer radii are also easier to complete and are more conducive to long horizontal sections.



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Drilling Program

The drilling program for our well is to provide the production department a well that will produce oil and associated gas from the target formation. The production interval has a target depth of 9,700 feet (2,957 meters) so the well will be drilled to a true vertical depth (TVD) of 10,000 feet (3,048 meters).

The term TVD means true vertical depth of the borehole and MD means the measured depth or length of the borehole. MD is the actual measured length of the drill string as the borehole was drilled.

This initial measurement is referred to as drillers depth. Once drilled, the well is logged, and logging operations are performed using a wireline logging tool, where the length of cable in the hole is measured and then compared to the drillers depth. Any variances have to be understood. The additional depth below the producing interval provides a rat hole or sump, and is drilled to enable the movement of pipe and other tools below the reservoir interval during completion and production operations.



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True Vertical Depth (TVD) – Depth of any location along the wellbore measured vertically downward from a surface reference, commonly the rig floor or mean sea level.

Measured Depth (MD) – Total distance drilled as measured along the wellbore. (In a vertical hole, MD = TD, or total depth).

Horizontal Displacement (HD) – Horizontal distance of any location along the wellbore measured horizontally from the wellbore location at the surface.



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Casing

There are thousands of different casing designs depending on the subsurface geology and fluids. This is a very simple example to explain basic concepts.

The conductor casing is typically installed to provide a secure wellbore through often unstable shallow sediments. The surface casing protects and isolates the groundwater from the borehole and borehole fluids. It also seals off shallow, high pressure gas zones.

Casing is run after drilling each interval with a drill bit larger than the casing outer diameter (OD). When "we drill out of casing" and deepen the well, the drill bit is smaller than the internal diameter (ID) of the most recent casing string.



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Each string of steel pipe or casing is then run through the process of cementing which involves securing the borehole by pumping cement down through the casing and up through the annular space between the casing and borehole.

The intermediate casing string is designed to connect the surface string to the top of the production interval where the production casing is run to complete the well.



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Blowout Preventer (BOP)

As each casing string is run, it is cemented in place and connected to the blowout preventer (BOP) using the casing head or flange. So at each stage, the BOP and casing form a single pressure containment system in order to control the downhole pressure in the event of a blowout.

Once the well is drilled to TD and completed, the BOP is replaced with a production wellhead, also known as the Christmas tree.



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Drilling Program

Days versus Depth Curve

This diagram is a Days versus Depth Curve showing the number of days planned for drilling. Actual days required are also plotted on a daily basis.

There is usually a close alignment between actual and planned days during development and production; however, in the exploration phase, there is often significant divergence. As each casing string is run, it is cemented in place and connected to the blowout preventer (BOP) using the casing head or flange. So at each stage, the BOP and casing form a single pressure containment system in order to control the downhole pressure in the event of a blowout.



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Drilling Program

Drilling Report

During drilling operations, a record is kept using a standardized IADC drilling report. This is filled out at the end of each tour (pronounced tower) every 8 or 12 hours. A record is made of all drilling operations and costs incurred during the tour.

The data comprehensively describes the equipment used and any changes to the bottomhole assembly (BHA), drill string and drilling mud, as well as on-going rig site operations.

The drilling supervisor is responsible for this and for delivering the information to the operating company representative, or “Company Man”. This information forms a permanent part of the well record.



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Review

In this module, you learned about:

Well function.

Drilling history.

Onshore drilling.

Offshore drilling.

Drilling program.



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Drilling Rig Components and Systems

Overview

The complete drilling system, includes the derrick, substructure, engines, fluid circulation system, pumps, blowout prevention system, drill string, and other necessary equipment for the drilling operation.

In this module, you will learn about:

Drilling rig components. Drilling systems. Rotating system. Fluid system. Blowout prevention system.



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Drilling Rig Components and Systems

Overview

This diagram summarizes the key components of a drilling rig, whether it is onshore or offshore. This will serve as a great reference to the specific parts of the drilling rig and its functions.

The mast is often referred to as the derrick and provides the support for the hoisting equipment and the complete drill string, and the rotating system in a Top drive or Kelly system. The derrick is also where the "stands" of drill pipe are stored or racked during tripping operations.

Below the rig floor, there are blowout preventers, through which the drill string passes during drilling operations. The drilling mud circulates from the mud pumps, down the drill pipe, up the annulus, back along the flow line into the shale shaker (where the drill cuttings are removed), and then to the mud tanks for reconditioning prior to recirculation.



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Drilling Systems

Power

The drilling rig, whether onshore or offshore, requires significant power and electricity to drill the well. Typically, this is generated by the onsite generator. It is referred to as the prime mover.

The person responsible for the prime mover and all of the electromechanical devices on the rig is referred to as the motor man.

Hoisting

The derrick supports the hoisting system. The drill line stored on the storage reel runs up into derrick or mast, where the crown block or pulley is.

The traveling block and drill hook are suspended from the drill line below the crown block and they “travel” up and down during drilling operations. The drill string hangs off the drilling hook.



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Rotating

The drill string consists of the tubulars and specialized components that hang off the drill hook. It includes the components required to rotate the complete drill string from the surface (either a Kelly or Top drive). The drill pipe and other drill string tubulars are connected to the kelly or top drive and the bottomhole assembly (BHA).

The drill pipe section includes drill pipe, and depending on drilling conditions, such specialized tubulars as reamers (to maintain hole diameter) and jars that are designed to “jar” the drill string free if it becomes stuck during drilling operations.

The bottomhole assembly will vary as a function of the projected drilling conditions and objectives of that section of the well.



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Rotating System

The drill string is rotated from the surface using the rotating system. Historically, drill string rotation was performed by the use of a Kelly, a hexagonal pipe connected to the drill string that fitted into the rotary table and rotated. This method requires connecting a joint of drill pipe every 30 feet (9 meters).

As rig economics and safety have driven the use of high-cost automated rigs, the drill pipe is now rotated directly by a Top drive. Decisions on the type of drill rig are made based on the cost per foot or meter to drill the well.

A Top drive enables drilling to take place in 90-foot (27-meter) increments rather than 30-foot (9-meter) increments, thus reducing the amount of time drilling and decreasing the overall cost per foot or meter.



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Drill String Components and Connections

The drill string is comprised of a number of components and has three main purposes:

To conduct fluids to the drill bit to allow the hole to be cleaned.

To apply rotary torque from the surface to the drill bit so that, in combination with axial force, the bit can break the rock and drill the hole.

To apply axial force to the cutting structure of the bit against the rock (this role is traditionally reserved for the BHA but modern design often includes drill pipe in this function).

This permits continuous drilling operations. The drill string is mostly comprised of drill pipe and a bottomhole assembly , referred to as the BHA, that is modified, depending on the drilling conditions. A traditional BHA has two purposes:

To control the directional well trajectory of the bit. To provide weight to be applied as axial force to the bit (it is often

partnered with the drill pipe to fulfill this requirement).

At any time during the drilling program, the drill collars and heavyweight drill pipe provide weight that will be exerted on the drill bit to drive it into the rock during drilling.

Drill pipe is strong in tension and drill collars are strong in compression, so the drill bit is loaded with force from the drill collars. During drilling operations, the direction and angle of the drill bit is monitored, as well as key petrophysical parameters using measurement while drilling (MWD) and logging while drilling (LWD) tools.

These are located a meter or so above the drill bit and the mud motor. MWD tools provide vital information in real-time. The mud motor is positioned immediately above the drill bit so that drilling can take place without rotation of the drill string. Together, all these components form the drill string.



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Non-Vertical Wells

Most wells drilled are either directional wells, or a combination of directional and then horizontal

Increase Production Rates• Unconventional Oil and

Gas Shale Plays

• Low Permeability Conventional

• Multi Laterals

Platform or Pad Drilling• Drill “vertical” wells from

a common point

• Extended Reach Drilling

Drill using a “Mud Motor” • Allows drill string to drill ahead without rotation

Drilling mud pumped through Mud Motor

Wellbore azimuth (angle of wellbore) and degree of dip (near real-time) sent back via the MWD and Geo Steering Tool

Top sub

Power section

Surface adjustable bent housing

Near bit stabilizerHousing

Rotor

Stator

Typical MWD Measurements• Torque

• Weight on Bit

• Borehole pressure

• Borehole Temperature

• Tool Face Angle

• Hole Deviation from Vertical

• Hole Azimuth with respect to Geographic Coordinates

Mud Motor

BHA = Bottom Hole Assembly PDM = Positive Displacement Motor



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Field replaceable stabilizer tomatch hole size and conditions

Logging While Drilling (LWD)

In the early days, wells were cored due to lack of methods forinterpretation, without analyzing the mud cuttings

LWD provides similar well data to Open Hole logging

Measurements are made during drilling:• Resistivity, Gamma ray, Density, Neutron, Sonic,

Borehole Imaging, NMR, Pressure, and Fluid Samples



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Bit Types

During drilling operations a number of drilling parameters are recorded and used to optimize drilling. In addition to drill collars and drill pipe, the drill string also includes the drill bit. The weight on bit (WOB) drives the bit into the rock as it is rotated.

Tricone Bits

The original rock bit at Spindletop was the classic tricone design, with steel cutting heads and teeth milled from steel mounted on bearings, each cone rotating independently. Cutting technology has improved to include tungsten carbide inserts for harder formations. In both of these types of drill bit designs (milled tooth and tungsten carbide insert), the rock is fractured, gouged, or abraded, depending on the type of cutting mechanism. Drilling mud pumped from the surface through the drill pipe and out through “nozzles" in the drill bit clean and cool the bit. Tricone drill bits are relatively inexpensive, but will fail and have to be replaced by round tripping from the bottom of the hole to the surface frequently. As the industry drilled harder formations, tungsten carbide inserts replaced steel teeth. This caused the roller cone bit bearings to be the primary cause of bit failure. Bit manufacturers responded by developing sealed bearing designs that extended bearing life to take advantage of this enhanced cutting action often well past 100 rotating hours “on bottom”. As the cutting structure dulls, the rate of penetration will often slow. If bearings fail, the torque will often increase and become erratic. One or both of these changes typically indicates that it is time to pull and replace the bit.



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PDC Bits

Today, when drilling through long sequences of sand and/or shale, be it vertically or horizontally, it is common to use PDC bits that have no rotating parts. The cutters are synthetic diamonds.

They are ideal for extended drilling over many days, using automated rigs. The combination of Top drive technology, mud motors and PDC bits provide the most economical drilling process.

Core Bits

During the exploration and appraisal phase, and often during mature water flooding operations, a core must be cut.

In this case, the rock bit is designed not to destroy the rock and create cuttings, but to cut a cylinder of rock “core” as drilling proceeds down through the formation.

The cylinder of rock is enclosed in a core barrel immediately above the core bit and when tripped out of the hole, a “core catcher” slides underneath the core and ensures it is recovered to the surface.



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Reviewed by the driller, the rig supervisor, and the company representative

• Condition of the teeth

• Condition of the bearings

• Whether it is in gauge or not

Recorded on the IADC drilling report

Drill Bit Condition

1/8 =Pulled green

7/8 =Worn out

Ser

ies

Fo

rmat

ion

sTy

pe

1 2 4 5 6 7S

eale

d

Geo

ther

mal

StandardRoller

Bearing

Unsealed Roller

Bearing Air Cooled

Sealed Roller

Bearing

Sealed Roller Bearing

Gauge Protection

Sealed Friction Bearing

Sealed Friction/Gauge Protection

Elastomer Metal Elastomer Air Elastomer Metal

Ste

el T

oo

th

1

So

ft

1RC111 GTX-1

RC114VG-1

GTX-G1RC115

VM-1MX-1

VG-1STX-1RC117

VM-1MX-1

2 RC121 RC124 RC125 VM-2 RC126 RC127

3 RC131 GTX-3VG-3

RC135VM-3MX-3

RC136 RC137 VM-3MX-3

4

2

Med

ium

1 RC211 RC215 RC216 RC217

2

3 RC236 RC237

4

3

Har

d

1

2 RC321

3

4 RC347

Drill Bit IADC Classification



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Ser

ies

Fo

rmat

ion

sTy

pe

1 2 4 5 6 7

Sea

led

G

eoth

erm

al

StandardRoller

Bearing

Unsealed Roller

Bearing Air Cooled

Sealed Roller

Bearing

Sealed Roller Bearing

Gauge Protection

Sealed Friction Bearing

Sealed Friction/Gauge Protection

Elastomer Metal Elastomer Air Elastomer Metal

Ste

el T

oo

th

1

So

ft

1RC111 GTX-1

RC114VG-1

GTX-G1RC115

VM-1MX-1

VG-1STX-1RC117

VM-1MX-1

2 RC121 RC124 RC125 VM-2 RC126 RC127

3 RC131 GTX-3VG-3

RC135VM-3MX-3

RC136 RC137 VM-3MX-3

4

2

Med

ium

1 RC211 RC215 RC216 RC217

2

3 RC236 RC237

4

3

Har

d

1

2 RC321

3

4 RC347

Bit No.Depth Out (ft)

Mean Depth (ft)

Bit Time(hrs)

Total Drilling Time (hours)

Avg. Penetration Rate (ft/hr)

Hole Size (in.)

1 473 237 1.0 1.0 473 15.00

2 1483 978 5.0 6.0 202 15.00

3 3570 2527 18.5 24.5 113 12.25

4 4080 3825 8.0 32.5 64 12.25

5 4583 4332 7.0 39.5 72 12.25

6 5094 4839 7.0 46.5 73 12.25

7 5552 5323 14.0 60.05 32 12.25

8 5893 5723 11.5 72.0 30 12.25

9 6103 5998 9.0 81.0 23 12.25

10 6321 6212 11.5 92.5 19 12.25

11 6507 6414 9.0 110.5 30 12.25

12 6773 6640 9.0 110.5 30 12.25

13 7025 6899 9.5 120.0 27 12.25

14 7269 7147 8.0 128.0 31 12.25

15 7506 7388 16.0 144.0 15 8.5


Bit No.Depth

Out (m)Mean

Depth (m)Bit Time

(hrs)Total Drilling Time (hours)

Avg. Penetration Rate (m/hr)

Hole Size (mm)

1 144 72 1.0 1.0 144 381

2 452 298 5.0 6.0 62 381

3 1088 770 18.5 24.5 34 311

4 1244 1166 8.0 32.5 20 311

5 1397 1320 7.0 39.5 22 311

6 1553 1475 7.0 46.5 22 311

7 1692 1622 14.0 60.05 10 311

8 1796 1744 11.5 72.0 9 311

9 1860 1828 9.0 81.0 7 311

10 1927 1893 11.5 92.5 6 311

11 1983 1955 9.0 110.5 9 311

12 2064 2024 9.0 110.5 9 311

13 2141 2103 9.5 120.0 8 311

14 2216 2178 8.0 128.0 10 311

15 2288 2252 16.0 144.0 5 216




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Drilling Fluid

The drilling fluid or mud circulation system is a key component in the successful drilling of oil and gas wells. It is essentially a combination of fluids and solids that together look like mud and whose components can be modified to fit the subsurface conditions.

It is mixed at the surface and then pumped down the drill pipe through the jet nozzles in the drill bit where it cleans, lubricates and cools the drill bit.

The drilling mud has a number of functions. It removes the drill cuttings from the bottom of the hole and transports them to the surface. At the surface, the cuttings are removed and the mud reconditioned, prior to being pumped back down the hole as a continuous circulation process. It also has a key role in pressure control and is fundamental to the rotary drilling process.



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Fluid System

The type of drilling mud and its properties, such as density, are determined by the drilling engineer as part of the well design and drilling program. The density and type of mud is determined by the pore pressure regime and geology that will be encountered while drilling through each stage of well construction.

The drilling mud is premixed and then monitored by the mud engineer at the wellsite. It is pumped up through the rotary hose, down the drill string, and through the jet nozzles in the drill bit, where it cools and lubricates the drill bit.

Most importantly it cleans and removes drill cuttings, transports them to the surface, then returns down the flow line, across the shale shaker, and through the degasser, removing gas and rock cuttings. The drilling mud is then reconditioned and stored in the mud pit to be recirculated.

Drilling mud fills the drill hole, and by doing so, exerts pressure on the wellbore. It is designed to exert a pressure greater than the formation pore pressure so that the well can be drilled safely. The wellbore is said to be overbalanced with regard to the formation.



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Drilling Fluids

There are two fundamental drilling mud types:

Oil-based – Most oil-based muds are actually environmentally friendly, inverted oil emulsions.

Water-based – Used to drill the majority of wells and the base fluid ranges from fresh water to saturated brine, often specifically mixed for the formations to be drilled.

Solids are suspended in this fluid, so drilling fluids are colloids.

Two key solid components of drilling mud are barite and bentonite:

Bentonite

Bentonite, also known as montmorillonite, is used in water-based mud only. It provides the mud-like appearance of drilling mud. This clay provides gel strength to the mud and also forms the seal (mud cake) that prevents the liquid phase from being lost to permeable formations as we drill through them.

This gel property allows drill cuttings to be easily transported while the mud is circulating, but is also designed to hold the cuttings in suspension in the borehole when not circulating.



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Barite

Barite, used in both water-based and oil-based muds, is added to the drilling mud to increase its density. Density is expressed in pounds per gallon, psi per foot, specific gravity and kilograms/cu meter. The intent is to create a drilling mud that exerts sufficient pressure so that the drilling fluid pressure is greater than the formation pressure without fracturing the formation. This is called the “drilling window”.

These physical and chemical properties of mud are recorded daily on the mud data report and monitored. If the mud properties do not meet the requirements of the drilling program, then action is taken.

Mud costs in automated drilling rig operations with extended laterals can be as much as one-third of the total drilling cost.



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Mud Pump on an Older Onshore Rig

Drilling Mud• Seal the formation

• Minimize formation damage

• Source of power when it isused in conjunction with apositive displacement motor

• Mud motor used to rotatethe drill bit without rotatingthe drill pipe

• Control formation pressure(the drilling window)

Drilling Fluid System









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Weighting Up

If the circulating drilling mud is insufficient to control the formation pressure, after activating the annular preventer, the drilling mud density is increased by pumping heavier mud down the drill pipe and up through the annulus.

Once the borehole is restored to overbalanced conditions, it is safe to continue drilling. This is called the “weight and wait”, or driller's method of kick control.

The next set of BOPs referred to are steel, and often seal at much higher pressures. Pipe ram BOPs are activated when the annular preventer cannot control the fluids that are flowing up the annulus. The mud pumps continue to exert pressure on the drill pipe during kick conditions to control fluid flow.



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Blowout Prevention

This diagram shows a BOP stack offshore in a high pressure, shallow water drilling environment. Under normal conditions, the drilling mud is pumped down the drill pipe and up the annulus.

It is common to encounter problems while drilling as a fluid (oil, gas or saltwater) enters the wellbore. If a kick occurs, the annular preventer is sealed against the drill pipe and prevents fluids flowing up the annulus. At the same time, any backflow up the drill pipe is prevented by the mud pumps when they are connected to the drill string.

The annular preventer allows for the movement "working" of pipe to minimize pipe sticking during kick operations. The drilling mud is the first line of defense to ensure that a drilling problem does not become an emergency.



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Pipe Rams

Pipe rams are normally placed on the bottom of the BOP stack. They also serve the function of sealing the annulus, but in a very different fashion from the annular preventers.

The pipe rams are the yellow BOP. The BOP is designed to close around the body of the drill pipe, rather than the larger tool. The pipe ram can be activated on the rig floor, or at remote locations.

Below is a cut-away image of a Pipe Ram.



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Blind Rams

The blind rams are also called shear rams, because they are designed to shear or cut the drill pipe, and when the two rams come together, they form a high pressure, metal-to-metal seal that closes off the downhole environment from the surface. When these operate correctly, we have a subsurface environment where the pressure is contained and controlled by the metal-to-metal seal of the shear rams.

Part of the design of the pipe and shear rams is that when the shear ram is activated, it shears the narrow part of the drill pipe, not the pipe joint. The pipe then drops but cannot fall through the pipe rams, because the drill pipe joint diameter is greater than the pipe ram diameter.



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Review


Drilling rig components. Drilling systems. Rotating system. Fluid system. Blowout prevention system.



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Casing, Cementing, and Wellhead Installation

Overview

During the drilling phase, the objective is to reach the production interval in a safe, timely, and economical manner, ensuring that no fluids flow into the wellbore from the formations being drilled through.

This is normally accomplished by "drilling overbalanced” with respect to the formation. When making the well ready for production, the well is completed so that oil and gas can flow from the reservoir into the bottom of the well, through the tubing, and up to the surface. This means that during production, the well is underbalanced with respect to the producing formation.

Well completion is the process of making a well ready for production.


Casing and cementing. Wellhead installation.



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Casing and Cementing

The well is drilled in sections and each section is cased and cemented. The purpose of casing is to:

Protect freshwater sands. Isolate formations. Contain formation pressure. Protect zones from fracturing. Anchor surface equipment. Provide a flow path for production. Protect tubing from corrosion.



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Casing String Design Considerations

Casing is the primary structural element of a typical oil and gas wellbore. It is most commonly tubular steel fitted with threaded connectors.

Casing comes in a variety of sizes as defined by its outer diameter, weights based wall thickness, and grades which define the strength characteristics of the steel. All of these are considered when designing casing strings to withstand pressures and other load conditions the casing will encounter in the wellbore over the life of the well.

Wellbores are constructed from a number of concentric strings of casing of diminishing diameter as the well is deepened. The illustration on the left shows how a casing program for a well might be chosen starting with the diameter of the smallest casing that is required at the bottom of the well and working uphole through larger casing sizes to the surface.



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The casing sizes shown are commonly used but this illustration does not include all sizes that might be considered.



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Casing and Cementing Components

Key casing string and cementing components include:

Float Shoe and Float Collar The float, or guide shoe, guides the first joint of casing into the hole and its depth.

Immediately above it, is the float collar, which controls the entry of drilling mud into the casing during the casing run. It allows the casing to be floated into the hole, minimizing the rig size and hoisting equipment specifications.

Wiper Plugs The wiper plugs are pumped ahead of and behind the cement slurry, separating it from the displaced fluid (drilling mud) and displacing fluid (drilling mud or completion fluids).

Centralizers The centralizers keep the casing centralized in the hole, ensuring better placement of cement in all parts of the annulus.



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Cement Integrity and Remedial Cementing

At the completion of each casing and cementing run, after the cement is hardened, the integrity of the cement sheath in the annular space between the casing and the drill hole is evaluated. It is pressure tested to ensure that there is no cement failure in the annulus.

An acoustic logging tool, referred to as a cement bond log (CBL) is also run from bottom up to identify any possible areas of non-coverage of the primary cement job.

If areas of incomplete cement placement are identified, remedial cementing, known in the industry as a "squeeze job” is employed. In this case, packers are set across the zone of concern, the casing is perforated, and cement is squeezed through those perforations and allowed to harden, filling the void space left by the initial cement job.

This can be carried out at any time during the life of the well.



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Casing and Cementing

Wellbore Schematic



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Production Wellhead



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Diverters

Flow control devices that are typically employed while drilling shallow, non-hydrocarbon bearing formations in a wellbore

Low-pressure devices and do not allow a wellbore to be shut in and circulated under pressure

If any uncontrolled flow from the well occurs, the diverters seal the annulus around the pipe in the wellbore and immediately opens a flow path away from the rig

Used in many different sizes and configurations

Annular Preventer

Pipe Ram or Variable Bore Ram (VBR)

Blind Ram or Blind Shear Ram

Flow Cross

Pipe Ram

Blow Out Preventer (BOP) Stacks



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Blow Out Preventer (BOP)

Casing is set and cemented in place

Connected to the Blow Out Preventer via casing head, which creates a continuous system of pressure control

Intermediate Casing

Production Tubing

Production Casing

Surface Casing

Production Casing

Surface Casing

Production Tubing

Intermediate Casing

Surface Casing Vent Line Assembly Surface Casing Bowl

Casing Head Spool

Christmas Tree

Wellhead Assembly

Christmas Tree Assembly

Tubing Head

Adaptor

Swab Valve

Wing Valve

Tubing Head Spool

Casing Head Spool

Surface Casing Bowl

Annulus Access



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Christmas Tree

Tubing Head

Casing Heads

Production Wellhead

Choke

Wing Valve

The Christmas Tree

Tubing Head Adapter

Wing Valve

Choke

Master Valve



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Review

In this module you learned about:

Casing and cementing. Wellhead installation.



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Well Completion and Stimulation

Overview

Upon completion of the well and installation of the production tubing, production packer, and wellhead, the next step is to bring the well into production.

Our well is a single zone completion with a rat hole of 300 feet (90 meters) drilled below the productive interval to provide room for the movement of logging and production tools below the reservoir.


Types of well completions. Formation damage and well perforation. Sand control problems and strategies. Well stimulation.



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Types of Completions

Single Zone

In a single zone completion, the production zone is isolated with a permanent production packer in the production tubing immediately above the zone that will produce.

This allows the bottom of the well to fill up to the packer, which when “set”, seals off the borehole annulus below it. This means that continued flow to the surface takes place only through the tubing.

At this point, there is a cement sheath and steel barrier to the flow of fluids into the well. The next stage is to perforate through the steel pipe and cement sheath and beyond the damaged skin of the near wellbore region, to create flow channels for the oil.



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Multi-Zone

It is not uncommon to have separate reservoirs or pay zones stacked on top of each other in a single well. This is common offshore, or where it makes economic sense to produce one or more pay zones in the same wellbore.

In order to optimize reservoir management, each of the three zones in this schematic is completed individually, with its own surface pressure and flow control. Producing the reservoirs individually avoids the practice of co-mingled production. In this practice, all three reservoirs produce through a single tubing string.



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Multi-Stage Horizontal Well

In a horizontal well completion, the well is completed from the farthest point in the lateral to the well heel, in stages.



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Formation Damage and Well Perforation

During drilling operations, the well is drilled overbalanced with respect to the formation using a drilling fluid composed of bentonite and drilling solids; both suspended in a brine or oil based fluid.

As the well is drilled in water (brine) based drilling fluid, the clay present in the sandstone reacts in varying degrees with the drilling fluid filtrate and expands, plugging the pores. Likewise, the mud cake that seals off the wellbore, seals off flow channels in the rock, and mud solids are driven into the pore channels in the near wellbore region, again reducing permeability.

The increase in water saturation near the wellbore region from the drilling fluid filtrate also creates unfavorable relative permeability conditions and minimizes the permeability to oil. These different mechanisms are referred to as formation damage and create a damage zone in the near wellbore region that acts as a choke on the flow of oil from the undamaged part of the reservoir into the wellbore. This is referred to as skin.

During completion design, the completion engineer will design the perforation phasing and density to optimize flow and drawdown conditions. The perforating gun carries the shaped charges which perforate through the casing, cement, and the near wellbore skin damage. These perforations provide a flow path from the reservoir to the well.



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Well Perforation

Two common technologies used to perforate the production interval deploy a perforating gun loaded with shaped charges. Once in position, both are activated from the surface.

Tubing conveyed perforating (TCP) guns are deployed latched to the end of tubing. They are lowered into the hole during tubing placement. Once deployed, they are fired and then unlatched, dropping down into the cellar or rat hole that was drilled below the producing formation.

In wireline conveyed "perf" guns, the gun is lowered down through the lubricator and tubing and then fired. The gun is then recovered to the surface. In both cases, operations will take place in underbalanced conditions to maximize well cleanup as flow commences.

When following the cement slurry during cementing of the production string, the displacing fluid will be a low weight completion fluid, creating the underbalanced production condition.



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Sand Control Problems and Strategies

When sand production occurs in sandstones, it erodes critical well equipment and creates safety and production issues:

Fills the production zone and tubing with sand. Sand build-up decreases production. Plugs surface equipment. Erodes well tubulars and surface equipment.



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Sand Control Problems and Strategies

Sand Production

Detrimental Effects of Sand Production• Erosion and abrasion of production tubulars

• Lost production

• Surface problems such as gas release and resultant fires



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Sand Control

Gravel packing works as a two part filter:

1. Appropriate size gravel is pumped down the tubing

2. The screen prevents the flow of gravel up the tubing

1.2.



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Well Stimulation

Stimulation strategies are used to restore or improve the permeability of the formation in tight sandstones and carbonate reservoirs, as well as those with extensive formation damage in the near wellbore region, where it is not possible to perforate though the damage.

Matrix acidizing removes formation damage by pumping acid from the surface through the tubing, and into the near wellbore rock matrix, at a pressure below the fracture pressure.

It is then allowed to spend and dissolve out the damage, and often, the original rock cement. This causes an increase in the permeability, compared to the initial reservoir conditions.



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Fracturing Technologies

Several types of fracturing technologies are used for well stimulation:

Fracture Acidizing Hydraulic Fracturing Slick Water Fracturing



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Well Stimulation – Fracturing

Fracture Acidizing

Hydrochloric acid will be used in the fracture acidizing process to chemically remove the limestone

Fracture pressure is exceeded and you see that a vertical fracture has been formed

Acid etches flow paths in the newly formed vertical fracture

Downhole pressure is relieved the fractures closes and fluid flow then occurs through the channels etched on the face of the fracture to the well

RESERVOIR

FracturesLimestone(Calcium

Carbonate)

Acid EtchedFlow Paths

HydrochloricAcid



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Hydraulic Fracturing

Hydraulic fluid is pumped intothe wellbore and pressure isconfined to the producing interval

It creates a vertical fractures inthe rock

The hydraulic fracturing fluid is“gelled”

Once the fracture pressure isrelieved, the fracture closes butis not completely sealed as theproppants keep the fracture open

The oil flows from the face of thefracture though the proppantsand then through theperforations into the wellbore

TightConsolidatedSandstone

Slick Water Fracturing

Micro-fractures



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Review


Types of well completions. Formation damage and well

perforation. Sand control problems and

strategies. Well stimulation.



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COPYRIGHTcloud1.activelearner.com/contentcloud/portals/...From exploration and appraisal into field development, the use of mobile offshore drilling rigs moves to permanent drilling

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