rig Hydraulics

Summer Internship Project Report

On

Optimization of Rig Hydraulics & Hole

Cleaning

For Internship Under

Drilling Department

Cairn India Limited

Submitted By-

Abhinav Goyal

University of Petroleum &

Energy studies

SUMMER INTERNSHIP PROJECT

Contents

BASICS OF HYDRAULICS ________________________________________________________________________________ 1

FLOW REGIMES __________________________________________________________________________________________ 2

FLOW ( RHEOLOGICAL ) MODELS ______________________________________________________________________ 4

ANNULAR PRESSURE LOSSES __________________________________________________________________________ 7

DRILLSTRING PRESSURE LOSSES ______________________________________________________________________ 8

HOLE CLEANING _________________________________________________________________________________________ 9

BIT OPTIMIZATION _____________________________________________________________________________________ 10

BIT HYDRAULIC ANALYSIS______________________________________________________________________________________11

MANGLA WELL ANALYSIS_______________________________________________________________________________________12

FIELD REPORT ________________________________________________________________________________________________20-47

REFERENCES ____________________________________________________________________________________________48


LIST OF FIGURES

FIG 1. Effect of ROP on min. flow rate for hole cleaning_____________________________13

FIG 2. Hole cleaning parameters _____________________________________________________ 13

FIG 3. Critical velocity vs depth _______________________________________________________14

FIG 4. Pressure losses vs rate _________________________________________________________14

FIG 5. Circulating pressure vs depth _________________________________________________ 15

FIG 6. ECD vs depth ___________________________________________________________________ 15

FIG 7. Impact force vs flow rate ______________________________________________________ 16

FIG 8. Bit pressure loss vs flow rate __________________________________________________16

Fig 9. Hydraulic HP vs flow rate ______________________________________________________ 17


ACKNOWLEDGEMENT

I would like to thank my respected mentor Mr. Deepak Sharma Sir for his able guidance

and support throughout the development of the internship project. His constant

suggestions have been valuable and his teachings during the course of my discussions

would continue to be guiding principle in my works in the future as well.

I would also like to Mr. Jayabrata Kolay Sir and Mr. Satyam Krishna Sir who were always

available for discussions at length at the various concepts that could be incorporated in the

project. Their suggestions and ideas helped me to develop our project successfully.

Finally I would like to thank the Cairn India Limited and the entire Drilling Department

for providing me an opportunity to apply my technical knowledge and see it materialize in

the form of this project.

Regards,

ABHINAV GOYAL


INTRODUCTION

The summer internship program at Cairn India Limited was an 8 week integrated learning curve,

blending the intricacies of Office work with the technicalities of drilling at rig sites. The internship

started with assigning of a major project in Office. I was assigned Optimization of Rig Hydraulics

and hole cleaning and its simulation using WellPlan module of LANDMARK software suite. I started

my project with building my basics about the topic and reviewing the Hydraulic analysis of

different wells to have a clear picture of what I would be doing. I selected Mangala Horizontal

producer for my analysis so as to cover all the aspects of hole cleaning and optimization in both

vertical and horizontal sections of a well and perform a comparative analysis. The whole office

project span continued for around 4 weeks wherein I completed my manual calculations of

Hydraulics and hole cleaning (pressure drop calculations, bit hydraulic calculations and vertical

well hole cleaning calculations) along with the interpretation of the graphical results generated

from the Wellplan Hydraulic module with my mentor.

A three week field trip to Barmer asset (Rajasthan) was lined up for the interns and we had to

select a topic for our field visit project. I decided to go with “Cementation and Pressure testing of

Casing”. The field experience was something that I never had since my exposure to Petroleum

Engineering but the internship at Cairn gave me the the opportunity to see Drilling, Wireline

logging and Cementing operations, all at different field sites which was a wonderful experience

mentored by the best professionals in the Indian oil field industry as well as expatriates from other

countries. I as an intern was grasping all the knowledge that I could get from the work going around

at the fields and studied the operations extensively by observation.

The last week of the Internship was all about collaborating all the knowledge that I have gained in

the previous 7 weeks, discussing the doubts regarding the projects and to deliver all that in a

systematic presentation form.

My internship at Cairn India during the 2013 summer gave me a huge amount of experience that

really has put me streets ahead of where I was when I started. Experience on a CV is immeasurably

valuable, and from a company such as Cairn India it is worth even more. I was given complete free

rein over a research topic tied into their current operations in Barmer, so I really did feel like one

of the team. My internship really has given me an excellent start to my career, and the whole

experience has been extremely enjoyable and invaluable.


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1. BASICS OF HYDRAULICS

The hydraulic system serves many purposes in the well. Since it is centred on the mud system, the

purposes of mud and hydraulics are often common to each other. The hydraulics system has

many effects on the well. Therefore, the reasons for giving attentions to hydraulics are abundant.

The more common reasons are as follows:

-Control sub-surface pressures,

-Provide a buoyancy effect to the drill string and casing,

-Minimize hole erosion due to the mud's washing action during movement,

-Remove cuttings from the well, clean the bit, and remove cuttings from below the bit,

-Increase penetration rate,

-Size surface equipment such as pumps,

-Control surge pressures created by lowering pipe into the well,

-Minimize well bore pressure reductions from swabbing when pulling pipe from the well,

-Evaluate pressure increases in the well bore when circulating the mud,

-Maintain control of the well during kicks

Hydrostatic Pressure

The hydrostatic pressure of the drilling fluid is an essential feature in maintaining control of a

well and preventing blow-outs. It is defined, in a practical sense, as the static pressure of a

column of fluid. Although the fluid is generally mud, it can include air, natural gas, foam, mist, or

aerated mud. Only liquid-based systems such as mud will be considered in this text. The

hydrostatic pressure of a mud column is a function of the mud weight and the true vertical depth

of the well. It is imperative that attention be given to the well depth so that the measured depth,

or total depth, is not used inadvertently. Since mud weights and well depths are often measured

with different units, the equation constants will vary. Common forms of the hydrostatic pressure

equation are as follows:

PH= 0.052 (mud weight, lb/gal) (depth, ft), PH= psia

If a column of fluid contains several mud weights, the total hydrostatic pressure is the sum of the

individual sections:

PH= ∑ c ρi Li

c = conversion constant

ρ = mud weight for the section of interest


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L = length for the section of interest

Equivalent Mud Weight

Drilling operations often involve several fluid densities, pressures resulting from fluid circulation,

and perhaps applied surface pressure during kick control operations. It is useful in practical

applications to discuss this complex pressure and fluid density arrangement on a common basis.

The approach most widely used is to convert all pressures to an "equivalent mud weight" that

would provide the same pressures in a static system with no surface pressure.

EMW = (total pressure x 19.23) / true vertical depth

EMW= equivalent mud weight, lb/gal

19.23 =reciprocal of the 0.052 constant

Buoyancy

The drilling fluid provides a beneficial effect relative to drill string weight or hook load. When

pipe is lowered into the well, the mud system will support, or buoy, some of the pipe weight. This

effect is termed buoyancy, or buoyant forces. The buoyed weight of the drill string will be less

than the in-air weight of the pipe. Buoyant forces are a function of the volume and weight of the

displaced fluid. Heavier mud has greater buoyant forces than low-density mud.

BW = BF x (in-air weight)

BW = buoyed weight, BF = buoyancy factor

2. Flow Regimes

While drilling fluids are flowing in a well, the manner in which the fluid behaves may vary. This

behavior is often termed the flow regime. The most common regimes are laminar, turbulent, and

transitional. Unfortunately, it is impossible to clearly define each type in the well.As an example,

mud flow may be predominantly laminar, although the flow near the pipe walls during pipe

rotation may be turbulent.

Laminar Flow

The most common annular flow regime is laminar. It exists from very low pump rates to the rate at

which turbulence begins. Characteristics of laminar flow useful to the drilling engineer are low

friction pressures and minimum hole erosion. Laminar flow can be described as individual layers,


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or laminar, moving through the pipe or annulus. The center layers usually move at rates greater

than the layers near the well bore or pipe. The flow profile describes the variations in layer

velocities. These variations are controlled by the shear resistant capabilities of the mud. A high

yield point for the mud tends to make the layers move at more uniform rates. Cuttings removal is

often discussed as being more difficult with laminar now. The cuttings appear to move outward

from the higher-velocity layers to the more acquiescent areas. These outer layers have very low

velocities and may not be effective in removing the cuttings. A common procedure for minimizing

the problem is to increase the yield point, which decreases layer velocity variations. An alternative

is to pump a 10-20-bbl high-viscosity plug to "sweep" the annulus of cuttings.

Turbulent Flow

Turbulence occurs when increased velocities between the layers create shear strengths exceeding

the ability of the mud to remain in laminar flow. The layered structure becomes chaotic and

turbulent. Turbulence occurs commonly in the drill string and occasionally around the drill collars.

Much published literature suggests that annular turbulent flow increases hole erosion problems.

The flow stream is continuously swirling into the walls. In addition, the velocity at the walls is

significantly greater than the wall layer in laminar flow. Many industry personnel believe that

turbulent flow and the formation type are the controlling parameters for erosion.

Transitional Flow

Unfortunately, it is often difficult to estimate the flow rate at which turbulence will occur. In

addition, turbulence may occur in various stages. It is convenient to describe this "grey" area as a

transitional stage.

Turbulence Criteria

The Reynolds number approach is used almost exclusively in the industry. Turbulence occurs when

the ratio of the momentum of the liquid to the viscosity ability of the liquid to dampen permeations

exceeds some empirically determined value. The momentum force of the liquid is its velocity times

its density. The viscous ability of the liquid to damp out permeations is the internal resistance

against change and the effects of the walls of the borehole. For the simple case of Newtonian, non

elastic liquid flowing in a pipe dampening effect is the quotient of the viscosity and the diameter of

the well bore.

NR = ρ V D / µ

NR = Reynolds number

ρ= density


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D = diameter

µ= viscosity

A simpler equation used in the literature to predict the Reynolds number at the upper limit of

laminar flow is as follows:

NR= 3,470 - 1,370 n

The relation for the Reynolds number between the transition and turbulent flow regimes is

NR= 4,270 - 1,370 n

It is obvious from equations that the Reynolds number is sliding, with its dependency on the flow

behavior index (n). The position of intersection between the laminar and turbulent flow pressure

losses depends on the equations being used.

Critical Velocity

The term critical velocity is used to define the single velocity at which the flow regime changes

from laminar to turbulent. This variable is the most important since all other members are

considered constant in a typical equation. Since no single Reynolds number defines the transitional

zone, it follows that a range of critical velocities may be necessary to determine the flow regime.

In practical applications, a critical velocity (Vc ) and an actual velocity (Val ) are calculated. If Val< Vc

the flow is laminar. If Vic< Va the flow is turbulent. If Val ≅ Vc calculations are made with both flow

regimes and the larger pressure losses are used.

3. Flow (Rheological) Models

A mathematical model is used to describe the fluid behavior under dynamic conditions. The model

can be used to calculate friction pressures, swab and surge pressures, and slip velocities of cuttings

in fluids. The models most used in the drilling industry are Bingham Plastic, Power Law and

Herschel Buckley.

Terms used in mud models are shear stress and shear rate. In drilling operations, the shear stress

and shear rate are analogous to pump pressure and rate, respectively.

Newtonian Fluids


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The model used initially to describe drilling mud was the Newtonian model, τ α γ. It stated that

pump pressure (shear stress) would increase proportionally to shear rate. If a constant of

proportionality is applied to represent fluid viscosity, τ = µ γ

Unfortunately, drilling mud usually cannot be described by a single viscosity term. They require

two or more points for an accurate representation of behavior. As a result, the Newtonian model

generally is not used in hydraulics plans.

Bingham Plastic

The Bingham model was developed to describe more effectively drilling mud presently in use.

Bingham theorized that some amount of stress would be required to overcome the mud's gel

structure before it would initiate movement τ = µpγ + τy

τy= yield stress, µp =fluid viscosity

In practical terms, the equation states that a certain pressure would be applied to the mud to

initiate movement. Flowing mud pressures would be a function of the initial yield pressure and the

fluid viscosity.

Shear rates are normally taken at 300 and 600 rpm rates on the viscometer.

The fluid viscosity (µp) and the yield stress (τy) are calculated as follows:

µp= θ600- θ300

θ600, θ300= readings at 600 and 300 rpm, respectively.

τy= θ300- µp

The fluid viscosity is termed plastic viscosity (PV) due to the plastic nature of the fluid and is

measured in centipoise (cp). The size, shape, and concentration of particles affect the plastic

viscosity in the mud system. As mud solids increase, the plastic viscosity increases. The plastic

viscosity is a mud property that is not affected by most chemical thinners and can be controlled

only by altering the state or number of solids.

The yield stresses τy, is given the name of yield point and is measured in lb/100 ft2 . It is a function

of the inter-particle attraction of the solids in the mud. Chemical thinners, dispersants, and

viscosifiers control the yield point.

Power Law

The Power Law model is a standard mathematical expression used to describe a non-linear curve.

The equation for drilling fluids is :


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τ = K (γ)n

K= consistency index; n = flow behavior index

The flow behavior index is descriptive of the degree to which the fluid is non Newtonian.

n = 3.32 log (θ600/ θ300)

K = θ300/ 511

Herschel - Buckley (Modified Power Law)

This model combines the features of the Newtonian, Bingham Plastic, and Power Law models. It is

a three parameter model that reproduces the results of the previous three models when the

appropriate parameters have been measured. Unfortunately, the three parameters are difficult to

derive from the rheometer readings. In practice, it is assumed that the YP is equal to the 3 rpm

reading. Using this assumption allows the calculation of the n and K values. The general form of the

equation is τ= YP + Kγn where

YP = θ3 (lb/100 ft2),

n = (3.32) log [(θ600– YP) ÷ (θ300– YP)],

K = θ300÷ 511n


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4. Annulus pressure drop calculations


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5. Drill string pressure loss


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6. Hole cleaning


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A major function of the drilling fluid is to transport drill cuttings from the bottom of the hole to the

surface where they can be removed. Poor hole cleaning can result in severe operational problems

including:

• High torque and drag

• Reduced rate of penetration

• Stuck pipe

• Difficulty running casing

• Primary cementing failures.

The ability of the fluid to clean the hole is dependent upon the rheology and density of the fluid, its

flow rate, and the size of the cutting. For any size particle (cutting), the upward movement of the

particle with the fluid flow will be partially negated by the effect of gravity that is promoting the

settling of the particle. The settling rate is termed the slip velocity ( Vs ). By comparing Vs to the

annular velocity ( Va ) in the interval, the net particle transport time (NPT) for the particle and the

annular transport time(ATT) can be calculated. These values will give the engineer the minimum

time required to transport a cutting to the surface.

Cuttings Concentration

When drilling the well, the rate of penetration may generate a larger volume of cuttings than can

be circulated out of the wellbore in one circulation. This results in a build up of cuttings in the

drilling fluid in the annulus. The concentration of cuttings ( Ca) in the fluid in any annular interval

can be calculated by using the following equations.

Depending upon the formations drilled, a Ca> 8% to 10% volume can result in hole cleaning

problems such as mud rings and pack-off.

7. Bit optimization


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Optimized hydraulic design is defined here as the determination of the jet nozzle sizes and flow

rates to satisfy an optimization criterion. Criteria used are the maximization of the bit hydraulic

power per square inch (HSI) or of the impact force (IF).

Constraints in this optimization process include rig capability limitations - maximum available

standpipe pressure Pmax, maximum horsepower of the rig pumps, minimum required and

maximum available flow rate, and downhole-tool limitations.

The goal of the optimization is to determine the total flow area TFA, the nozzle sizes and the flow

rate to deliver maximum bit hydraulic horsepower (HSI) or impact force (IF) within the limitation

of maximum pump pressure and hydraulic power available from the drilling fluid pumps.

Some drilling programs select flow rates by using the maximum possible jet velocity for a particular

selected annular velocity. Jet velocity increases as the pressure across a nozzle increases. The flow

rate in the circulating system is selected to be as low as possible to provide the maximum pressure

available for the drill bit. Some rule-of-thumb guidelines recommend that the nozzle velocity be

maintained above 230 ft/s to reduce the possibility of plugged jet nozzles.

The parasitic pressure loss, which includes all pressure losses in the system except the bit pressure

drop, is calculated using the equation:

PParasitic = KQu

Determine the slope u and the coefficient K of the parasitic pressure loss equation and apply the

optimization.


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8. Bit hydraulic analysis


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MANGALA GENERIC WELL

MANGLA FIELD

HORIZONTAL PRODUCER

8-1/2 in. HOLE HYDRAULIC ANALYSIS


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Fig.1 Effect of ROP on min. flow rate for hole cleaning

Fig 2. Hole cleaning parameters


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Fig 3. CRITICAL VELOCITY VS DEPTH

Fig 4. PRESSURE LOSSES VS RATE


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Fig 5 Circulating pressure Vs Depth

Fig 6. Ecd vs depth


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Fig 7. Impact force vs Pumprate

Fig 8. Pressure loss Vs Rate


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Fig 9. Bit power Vs pump rate


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CONCLUSION


Page 20


Page 21

CEMENTING This section of the report highlights the process of primary cementation along with different

surface & subsurface cementing equipment. Cementing an oil or gas well comprises the

displacement of cement slurry down the drillstring, tubing or casing to a predefined section of

the annulus of the well. The cement slurry itself typically contains water, portland cement and

various additives.

Functions of Cement

1. Isolate a hydrocarbon bearing formation from other formations,

2. Protect and secure the casing in the well,

3. Prevent caving of the hole,

4. Provide a firm seal and anchor for the wellhead equipment,

5. Protect casing from corrosion by sulfate rich formation waters

Cement Slurry

API has defined standard classes (Class A to Class H) as well as standard types of cement used within oil

and gas wells. The standard types are:

1. Ordinary,

2. Moderate sulfate-resistant,

3. High sulfate-resistant

Commonly Used class of cement is Class G.

Class G: Intended as basic cement in the depth range: surface to 8,000 [ft], when used with accelerators

and retarders covers wide range of temperatures and pressures, available in moderate and high sulfate-

resistance types.

The physical properties of cement and cement slurries include:

1. Thickening time,

2. Water content,


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3. Slurry density,

4. Compressive strength

5. Fluid loss

6. Yield

Cement slurry additives

1. Accelerators: chemicals which reduce the setting time of a cement system, and increase the rate of

compressive strength development.

2. Retarders: chemicals which extend the setting time of a cement system.

3. Extenders: materials which lower the density of a cement system, and/or reduce the quantity of

cement per unit volume of set product.

4. Weighting Agents: materials which increase the density of a cement system.

5. Dispersants: chemicals which reduce the viscosity of a cement slurry.

6. Fluid-Loss Control Agents: materials which control the loss of the aqueous phase of a cement system

to the formation.

7. Lost Circulation Control Agents: materials which control the loss of cement slurry to weak or vugular

formations.

8. Specialty Additives: miscellaneous additives, e.g., antifoam agents, fibers etc.

Cementing equipment

1. Surface equipment

1. Cement storage vessel (silo) Powdered cement material is delivered into the silo through a closed system. The cement is aerated by

the delivery tanker and transferred through heavy-duty hoses from the delivery tanker to a rigid pipe

to the bottom of the silo using compressed air. The delivery driver controls the discharge rate and driver

adjusts the flow of air in to the tank and consequently the rate of flow of cement into the silo.

The silo is fitted with a pressure release vent line at the bottom which connects to dust collector to

allow air to escape through filters which control dust emission.


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2. Surge tank

For proper mixing operations the supply of cement should be steady, and the pressure at the mixer

bowl should remain constant. The bulk cement is moved from the storage tank toward the cement

mixer, driven by the differential pressure created between the tank and the end of the line. If the line

is longer the cement tends to separate from the conveying air into slugs, giving pulsar flow. To smooth

the flow and allow for operational requirements, such as changing from one storage tank to another, a

surge tank is used.

3. Continuous mixing unit- Schlumberger

This cementation unit is state of art mixing and pumping unit for land operations. The power unit allows

mixing and pumping cement at rates to 17bbl/min and at pressures to 10,000 psi. Pumps are available

with rating to 10,000 psi. A SLURRY CHIEF mixer with automated density control is used in conjuction

with 6 bbl. mixing tube and a 14 bbl. averaging tank. This arrangement produces superior density

control and separates the critical mixing stage. It also provides the ability to mix 20 bbl of cement in

batch mode for squeeze and plug operations. The CemCAT system is used to monitor and record

treatment parameters and to provide a job report.

CEMENT STORAGE - SILO


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Features

Two triplex pumps with 260 hhp power per pump

17 bbl/min max pump rate

Working Pressure rating to 10,000 psi

Automatic density control

Two nonradioactive densitometers

Four Centrifugal pumps for reliability

CemCAT real time monitoring

4. Batch Mixer Twin 50 bbl. batch mixers are available for mixing of cement slurries or other fluids. The Unit features

two centrifugal pumps for picking up fluids, recirculating for mixing and for delivering fluid to high

pressure pumps.

2. Subsurface Equipment

1. Wiper plugs

Wiper plugs are elastomeric devices that provide a physical barrier between fluids pumped inside the

casing. A bottom plug separates the cement slurry from the spacer and a top plug separates the cement

slurry from the displacement fluid. The bottom plug has a membrane that ruptures when it lands at the

bottom of the casing string, creating a pathway through which the cement slurry may flow into the

SCHLUMBERGER CEMENTING UNIT


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annulus. The top plug does not have a membrane; therefore, when it lands on top of the bottom plug,

hydraulic communication is severed between the casing interior and the annulus.

2. Float collar & float shoe

• Acts as check valve

• Prevents cement back flow into casing

• Typically run in pairs

• Available in differential fill design

• All components drillable

BOTTOM PLUG (INSIDE VIEW) FLOAT SHOE


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Pre cementing considerations

1. Circulate the well before cementation job for at least 1.5 complete volume cycles. ( can be 1.5

-2.5 times hole volume).

2. Stage pump rate to the maximum rate planned during the cementing operation. Monitor well

for whole mud losses

3. Check that there are no gas shows while circulating with pipe on bottom.

4. Mud should be conditioned to exhibit “easy-to remove” properties including low fluid loss, thin

rheological properties, and a flat gel profile.

5. Ensure that the dry bulk supply lines from silo to surge tank (and batch mixer) are clean and

vented thoroughly by blowing air through these lines.

6. Don’t fluff lightweight blend because that can induce particle segregation.

Procedure for primary cementation of production casing

1. Make up SLB cementing head, one pumping line from mud pump and cementing line from SLB

fly mixing unit.

2. Flush cement line with drill water and pressure test line to low pressure 300 psi and high

pressure 3300 psi.

3. Break circulation with mud and circulate 150% hole capacity = 427 bbl. = 5144 strokes. Break

circulation slowly and increase circulation rate in stages to 5 bpm = 60 spm while monitoring

losses.

4. Reciprocate casing while circulating and displacing fluid. Land casing when 50 bbl. is remaining.

CEMENTING HEAD


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5. Batch mix 95 bbl. of 13.0 ppg slurry.

6. Drop bottom plug #1.

7. Pump 75 bbl. 11.5 ppg weighted spacer at 5 bpm with mud pump @ 60 spm. Total strokes 903.

8. Isolate rig circulating system from cementing manifold.

9. Release lower wiper plug #2.

10. Fly mix 44 bbl. 13 ppg cement slurry @ 5bpm.

11. Pump remaining 95 bbl. batched 13 ppg cement slurry @ 5bpm.

12. Drop Top Plug.

13. Start displacement from unit, pumping a total of 166.1 bbl. of water at following rates

100 bbl. of water @ 5bpm



6.10 bbl. of water @ 1.0bpm

14. During displacement reciprocate the casing with stroke length 10ft.

15. Bump plug with 500 psi over final circulating pressure. If plug not bumped, pump additional

1.45 bbl. (1/2 of shoe track) = MAXIMUM 167.55 bbl.

Procedure for pressure test casing

1. If plug bumped, line up SLB cementing unit and isolate rig pumps. Pressure test casing with

cement unit using water to 4000 psi for 10 minutes and record the fluid volume pumped.

2. Bleed off pressure and check if float is holding – record the fluid volume returned.

3. If float is not holding re-bump plug, close all cementing head valves and WOC. Check for

backflow every 30 minutes.

4. If float is holding, rig down all cementing lines and cement head.

Contingency plan

1. Acceptable density window for fly mixed slurry is from 12.9 ppg to 13.10 ppg.

2. In case the float is not holding the Master valve has to be closed. Keep checking every 4 hrs.

and when the return stop, open the casing to atmosphere.

3. If the pump does not bump (after pumping the calculated volume of displacement). Do not

overdisplace more than half shoe track volume i.e. 1.45 bbl.

Special considerations

1. Centralisation Casing stand-off through critical sections should be a minimum of 70%. Standoff is defined as NAC/ (HR-

CR), where NAC = the Narrowest Annular Clearance between the casing and the wellbore, HR = hole


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radius, and CR = casing radius (CR). Standoff can range from 0 % (casing against the hole wall) to 100 %

(casing perfectly centered in the hole).

Deviation < 45 degrees = 1 centralizer per 30 ft joint

Deviation > 45 degrees = 2 centralizers per 30 ft joint (For tight radius bends and severe doglegs, adding

2 centralizers per joint may increase the rigidity of the casing string such that running in the hole may

be more difficult.)

2. U-tubing & cement free fall Cement slurry density inside pipe is greater than the density of the fluid in the annulus, so it will fall to

seek an equilibrium. With a closed system this will tend to pull a vacuum at the wellhead. The rate of

fall depends on density differential and friction factor. Hold back pressure if needed and modeling can

be done with cementing simulator

3. Two bottom Plugs To prevent contamination of spacer/mud and spacer/cement in the casing. The procedure for usage of

two bottom plugs:-

1. Place both bottom plugs in the cement head, resting on pull pin #5 & #6.

2. Circulate the well by opening valve #4.

3. Drop 1st bottom plug

a. Open valve #3 (equalize pressure)

b. Open pull pin #6

c. Close valve #4

d. Pump the spacer using valve #3

4. Load top plug in cement head

a. Open valve #2, #3, #4 (equalize pressure)

b. Close pull pin #6.

c. Open top cap #1.

d. Open pull pin #5 to shift 2nd bottom plug above pull pin #6.

e. Close pull pin #5

f. Place top plug on pull pin #5.

g. Close the top cap #1.

h. Close valve #2, #3, #4

5. Top and Bottom Plug having been loaded in the cement head, the process would proceed as

per normal procedure with spacer already pumped.


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HOISTING SYSTEM This section of the report covers a basic idea of the hoisting system and its immediate and

interim uses during operations at various stages of the process of drilling a well. It would also

include the some of the rig specification from the rigs that were visited during the field trip of

the internship.

The Drawworks

Peculiar Features:

Heart of the rig

Enabling equipment to be run in and out of the hole

Provide power for making or breaking joints

Principle components: drumshaft group, catshaft and coring reel group, main drive

shaft and jacketshaft group, rotary component group, and controls

Drumshaft group

It is the main shaft involved in the Hoisting drum to reel the line to raise and lower loads.

Components include:

DRAW-WORKS


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Brakes; used to stop the movement using the brake lever

Cooling system; water cooling system to remove heat generated during braking

Auxiliary brakes; hydrodynamic (hydraumatic) or eddy current (uses magnetic forces)

Some other shafts in the Drawworks include:

Catshaft: It comprises the catheads and the catshaft assembly. The Mechanical catheads are

spooled with a suitable length of wire line connected to the tongs. The tongs on the driller’s

side is called make-up tongs and on the other side called break-out tongs.

Coring reel drum: It contains sufficient small diameter (9/16 in) wire line to reach the bottom

of the hole, generally Used for lowering and retrieving any device to the hole bottom.

Main drive shaft and jacket group: They are used on many modern rigs to generate electricity.

Electric cables used to deliver power to motors attached main drive power to the main drive

shaft, rotary table and mud pumps.

Rotary countershaft group: Required when the rotary table is powered directly from the draw-

works.

Hoisting tackle

Block and tackle system is used to handle weight of drill string. Continuous line is wound

around a number of fixed and traveling pulleys.

Here, the line segments between sets of pulleys act to multiply the single pull exerted by the

hoisting drum. This allows many thousands of pounds of drill string or casing to be lowered

into or pulled from hole. It includes different components: crown block, traveling block and

drilling hook, dead line anchor and weight indicator, and drilling line

Crown block

It provides means of taking wire line from the hoisting drum to the traveling block. Basically, it

is a collection of number of pulleys fastened to the top of the derrick.

The drilling line is reeved around the crown block and traveling bock sheaves. One end comes

to an anchoring clamp called dead line anchor. The other end goes to the hoisting drum

described as fast line. During hoisting the drum spools more fast line than the distance traveled

by the traveling block. The speed of the dead line is zero while that of the fast line is equal to

the number of drilling lines times the speed of the traveling block. Crown block must be

positioned such that the fast line sheave is close to the center line of the hoisting drum.


Page 31

Reeving Process

Reeving means to string up the drilling line through the hoisting system. Reeving is mostly done

with mast laid down on horse back or in vertical position.

a. Pick up one end of the drilling line; pass it through the slot on the substructure from where it goes over the dead line anchor.

b. The crewmember then pass the line over the dead pulley, pulling it all the way to the traveling block, which is previously placed in the middle of the mast. Crane or forklift can be used to drag the line for reeving.

c. Line end is passed around the first pulley of the traveling block, and pulled back to the crown block.

d. Same procedure is repeated till the line has passed over all required number of pulleys in crown and traveling.

e. After passing the line end through the last pulley, which will be called fast sheave, line is dragged to the Drawworks drum and secured it there.

f. Driller starts the Drawworks and reeves in sufficient number of wraps on the drum, while crew keeps on loosening the line from the spare line drum.

g. Pass the other end of the line through the dead anchor and clamp it and secure it. h. Drilling line is now reeved in and is ready for use.

Note: The angle formed by the fast line and the vertical is called fleet angle. Fleet angle should

be less than 1.5 deg.

Crown block as it is clear from the above is a steel framework with the sheaves mounted

parallel on a shaft. The sheaves are mounted on a double-row tapered roller bearings to

minimize friction. A sheave for the line from coring reel shaft is also on the block. Small sheave

for the manila rope from friction catheads may be also found.

Traveling block and drilling hook

It is similar to the crown block as it also contains sheaves and helps in hoisting the drill string

(running in and pulling out of hole). Manufactured from high quality steel, each pulley

mounted on large diameter of anti-friction bearings. Sheaves diameter should be 30-35 times

the diameter of the drilling line to prevent excessive wear and increase fatigue life of line.

Manufacturing Constraints

• Short and slim for less room


Page 32

• Heavy to overcome the drilling line friction

• Free of protrusions and sharp edges for safety of workers

It is combined with the hook into one unit named “Hook Block”. The hook is used to connect

the traveling block to the swivel and the rest of the drill string.

Deadline anchor and weight indicators

A base and slightly rotatable drum attached to the rig floor, it provides a means of securing the

dead line and measuring the hook load. Hook load measured by a sensitive load cell or pressure

transformer. Here, a pressure signal is sent to the rig floor through a fluid filled hose connected

to a weight indicator. The weight indicator has two pointers; one shows total hook load and

other weight on bit.

Slip and Cut Practice

After calculating the ton miles during drilling, tripping etc. the drill line is slipped and cut at

particular length so that wear in the line is spread as uniformly as possible over its entire length

and at the same time the critical load areas are shifted. During slipping phase the deadline

anchor brake is slacked to allow the drill line to slide through. For cutting the block line has to

Hook load indicator


Page 33

be removed from the Drawworks drum. The block hanging line hangs traveling Block. Special

precautions have to be taken during the operation.

Drilling line

A wire rope made up of number of strands wound around a steel core. Each strand contains a

number of small wires wound around central core. Several types of wire ropes:

• Round strand

• Flattened strand

• Locked coil

• Half locked

• Multi-strand

The Basic difference in all these above types is related to the following parameters:

• Internal structure

• Weight per unit length

• Breaking strength

• Number of wires in each strand

• Number of strands

• Type of core

In oil well drilling, round-strand wire are only used. Peculiar features of Round-strand ropes

are:

• Widely used in most hoisting operation; oil or mining

• More economical than others

• Consists of six strands wound over a fiber core or a small wire rope

• The wire rope described by the number of strands

Described as: either 6x9/9/1; means 6 strands each consists of 9 outer wires, 9 inner wires,

and one central core, or 6x19, meaning 6 strands each contains 19 wires

Also described by the type of lay: Lang’s lay or ordinary (regular) lay

Lang’s lay, wires and strands are twisted in the same directions; right hand or left hand. This

type of twist increases wire rope resistance to wear.

Ordinary lay; wires and strands twisted in opposite direction, with major advantage being that

it is easier to install and handle than lang’s lay


Page 34

Drilling line design considerations

Typical line is round-strand, Lang’s lay, 6x19 construction with independent wire rope core

(IWRC)

Sizes varies from ½ to 2 in (51 mm)

Described by nominal diameter, mass per unit length and nominal strength

Specifications given in API Spec 9A

Slips and Elevators

Slips are used to hold the weight of the drill string. The slips are placed around the drill pipe

and lowered into position with the pipe into the rotary table.

Due to the weight of the drill string, slip dies bite into the pipe body and holds it in place by

wedge action. Slips must be maintained in good condition with all pins, elements and dies

inspected regularly. Slips must be set and removed correctly to minimize damage to pipe and

the slips themselves.

Floorman are close to the elevators and blocks when the slips are set and lifted. Slips are heavy;

they must be handled by the correct number of crew and should be left properly balanced.

Power Slips are hydraulic or pneumatically operated slips used on the rig floor to avoid manual

handling of the slips. Spider Elevators and slips are also pneumatic operated slips used during

running in of casing, when casing weight is very high and more than the capacity of the manual

side door elevator, but always before casing enters open hole.

Tongs Rig tongs are on the rig floor for making up and breaking out pipe.

One tong is fastened by a sling of required length to the make-up piston end and the other end to the break-out piston end Moreover snub lines are attached from the tongs to anchor posts on both sides. The tong jaws are latched and set on each side of the pipe coupling. For making


Page 35

up a connection, the make up piston is pulled up to apply torque through the tong. The second tong through onto the anchor post takes up the reaction torque. The process is reversed for breaking out a connection. Tongs are tied back clear of the rotary table when not in use. Tongs are hung on a special suspension line run over a sheave up the mast to a counter weight. This allows the tongs to be raised or lowered to the tool joint height. Power Tongs are used to make up or break out drill pipe or casing/tubing connections by

engaging the tong jaws around the connections and then rotate to accurately torque up or

break out the tubular. Spinning of the joint is done at high gear and torque up at low gear or

breaking out is done at low gear. Power tongs are normally hydraulically driven. For some

power tongs a rig tong is used for backing up or breaking out a connection while with some

other power tongs the back up device is an integral part of the tong.

Power Tong is hung from the crown block if it is part of the rig floor equipments like Hawk Jaw

and tongs like casing power tong are hung on winch line. They should be secured in one corner

after use. Hydraulic unit of the tong is kept away from the rig floor.

Job description of Cranes operating on rig site: For moving equipments on to the rig floor, using crane, bring the equipment close to the rig floor, using forklift if possible. Hook up crane using inspected slings and shackles. Raise the load, make sure it is balanced and slings are all clear. When lowering the load on to the rig

POWER TONGS PIPE SPINNER


Page 36

floor, crane operator to follow the instructions of signalman. At all times there should be only one person giving signals.

Man Riding

Man Riding (using the air winch and a riding belt to lift a man up) is sometimes required for

special or unforeseen operations in the derrick and substructure. A special riding belt is fitted

about the rider waist, the winch line shackled to the lifting eye and the rider hoisted on the

winch. Man riding can only be performed under special conditions and only with a certified

Man Riding winch and a man riding basket.

HSE Warning: Both rider and winch operator need to be experienced. Man Riding winch is not

to be used for any other lifting purposes.

Working on Monkey Board The Derrickman works most of the time alone on the monkey board. His job is to open the

elevator, and retrieve the stand of Drill Collar or pipe and rack it in the finger during pulling out

of hole and to throw the pipe into elevator and close the elevator during running in. He should

Man Riding Equipment


Page 37

be properly trained in the job. Sometimes due to the addition of down hole tools, stands of

BHA have awkward height. Derrickman is required to handle the stands from monkey board.

Winches are installed on the rig floor, the monkey board and in the substructure. Winches may

be hydraulically operated or air operated.

Monkey board winch is a smaller winch, installed on a pedestal, for pulling the drill collar stands

for racking. As Derrickman is working alone most of the time and at such a height, he should

take care of his own safety while operating.

Rig Specifications

JE#18

Derrick a) Type Telescopic mast Make LCI

B) Height 122Ft

Travelling Block a) Make american block

b) Type block with unitized hook

c) Rating 250 mt ; 5 sheave; 1 1/8" groove

Draw works a) Make LCI - 1100

b) Type Removable brake flange

AIR WINCH


Page 38

42" Dia x 12" Wide

c) Drum Diameter 18" x 39"

Wire rope size a) Make Usha martin

b)Details 1 1/8" dia, 6x19s construction

Engines a) Make Caterpillar C-15

b) Type Diesel driven

c) Rating 540 HP

Mast Model 122 x 440 Twin Box (per API 4F) Key Features:

• Twin box leg fixed base design allows fast positioning of rig before mast is raised. Clear height is 122' below crown.

• Crossover crown with 36" fast-line sheave plus five 30" sheaves. All sheaves mounted on Timken double-row bearings.

• Two hydraulic raising rams and two hydraulic telescoping rams. WE#807

Derrick a)Make NOV Rapid Rig

b) Height 100 ft

Travelling Block a) Make NOV

b) Type block with unitized hook

c) Rating 250 mt ; 5 sheave; 1 1/4" groove

Draw works a) Make NOV SSGD-250

b) Type Baylor AC Cage Induction Motor

Wire rope size a)Details 1 1/4" dia, 6x19s construction

Engines a) Rating 1000 HP

Top Drive a)Make NOV TDS 10SA


Page 39

CORING

In hydrocarbon exploration and development, obtaining geological data is a primary objective.

In general, geological data are gathered from direct observation and analysis of rock cuttings

collected at surface during drilling. The geological informations thus available are valuable, but

are limited by:

Size of individual rock fragments

Rock sample contamination

Under-representation of formation of interest

In hydrocarbon exploration, cutting of core is the only way that provides intact specimens of

the selected formation for anatomy. The need to obtain information and examine formation

rock of interest, led to the development of coring techniques. Correspondingly, development

of core analysis techniques played a large part in understanding the formation characteristics

and improving the other formation evaluation techniques. Coring also helps in meeting

operators' current need for geological, drilling, completion and engineering requirements in

hydrocarbon exploration and exploitation.

GENERAL CORING METHODS

The coring methods are classified into three types:

Conventional coring method

Wire line coring method

Side wall coring method

GEOLOGICAL DATA AVAILABLE FROM CONVENTIONAL CORES

Formation lithology

Rock characteristics

Formation thickness

Stratigraphic sequence

Environment of deposition

Fracture studies

Core Log correlation

Minerology

Diagenesis


Page 40

CONVENTIONAL CORING

The conventional coring is done using regular drilling equipment and rotary drilling method. This method utilises open centre bit (core bit) which cuts doughnut shaped hole, leaving cylindrical formation rock (core) in the centre. As the drilling operation progresses, the cut core rises inside the hollow tube called inner core barrel placed above core bit where it is captured and brought to surface for analysis. The size of cores cut depends on the available core barrel sizes, the size of core ranges from 1 V8" to 51/4" diameter. Many of the available conventional core barrels are able to cut 30 to 60 ft of core. Coring operaiton with conventional core barrel

Various components including the outer ba"el or body, the inner barrel that contains the core,

and the bearing and ball/seat assembly are shown. Also, a conventional diamond core bit is

illustrated, showing how the inner barrel and core catcher is arranged. Mud (indicated by

arrows) must flow through the tight annular space between inner and outer barrels and is one


Page 41

area of concern in coring, especially when using lost-circulation materials, as they can lodge in

this space and jam the inner barrel.

Description of coring tools CORE BITS: Drag type, roller cone and diamond bits are used for coring. The core bits are also called as 'core heads'. CORE BARREL The core barrel has two sections; one outer core barrel and second inner core barrel.

Outer core barrel (OCB) Outer barrel is the outer body of core barrel houses inner core barrel (catcher) and connects the core bit. The size of outer core barrel is smaller than the diameter of hole drilled. This allows washover/fishing in case core barrel gets stuckup.

Inner core barrel (ICB)

The function of inner core barrel is to accept and store core as formation rock is cut. The inner core barrel is attached to the outer core barrel at the upper end. A swivel bearing system at the upper end allows the inner core barrel to remain stationary while outer core barrel rotates along with core bit. At the lower end of inner core barrel are the core catcher bowl and core catcher. This assembly catches and retains core and also helps to break up the core free from formation.

Core barrel Inner fibre core barrels


Page 42

Mud flow during drilling Through the drill string, mud enters into core barrel top, then the mud flow is diverted into the annulus between inner core barrel and outer core barrel by ball check valve placed at the upper end of inner core barrel. Then the mud passes around core catcher down to cutting area of core bit.

Handling of cores Cores are cut in hard rock areas, unconsolidated sands, fractured formations etc. Surface handling of softer cores is different as the samples fall out of conventional core barrels during recovery. To minimise such damages and improper core recovery, replaceable and reusable inner core barrels are used.

Cleaning of core for visual inspection Spectral gamma logging


Page 43

CIRCULATION SYSTEM

What is the circulation system?

The circulation system is the lifeline of every oil well. It is the system through which the

drilling mud travels down from the active mud tank-mud pumps-standpipe-gooseneck-

drillstring-bit and then up the annulus to flowline-shale shaker-desander-desilter-degasser

(mud conditioning equipments) to intermediate mud tank. During the cycle mud lifts the drill

cuttings to surface and acts as lubricant and coolant for the bit and drillstring.

Circulation system is one of the most important system without which we cannot drill

to the target depth. Each component of circulation system is available in number of sizes,

capacity and pressure rating; so their selection depends upon the rig size, target depth and

concerns of primary well control. The next section discusses the various components of mud

circulation system.

Components of circulation system:

1. Mud Tanks and mud mixing equipments

2. Mud pumps

3. High pressure mud flowline

4. Drill string-Bit Nozzles-Annulus

5. Shale shaker

6. Degasser

7. Mud cleaner (Desander plus Desilter)

Drilling mud is the single component that remains in contact with the wellbore throughout the

drilling operation. A properly designed and maintained drilling fluid performs several essential

functions:

Cleans the hole by transporting drilled cuttings to the surface, where they can be

mechanically removed from the fluid before it is recirculated downhole.

Balances or overcomes formation pressures in the wellbore to minimize the risk of well

control issues.


Page 44

Supports and stabilizes the walls of the wellbore until casing can be set and cemented

or

Openhole completion equipment can be installed.

Prevents or minimizes damage to the producing formation.

Cools and lubricates the drillstring and bit.

LWD-MWD data transmission by mud telemetry.

The properties of the mud are checked continuously to ensure that the desired properties of

the mud are maintained. If the properties of the mud change then chemicals will be added to

the mud to bring the properties back to those that are required to fulfill the functions of the

fluid. These chemicals will be added whilst circulating through the mud pits or mud with the

required properties will be mixed in separate mud pits and slowly mixed in with the circulating

mud.

Mud Pumps:

With the exceptions of some experimental types, rigs always have been using positive

displacement reciprocating pumps. The reason behind using reciprocating pumps is their

ability to pump highly solid laden fluids and ability to operate over wide range of pressures and

flow rates by changing the liner size.

There are basically Triplex pumps (single acting) and Duplex pumps (double acting) being used

widely. Triplex pumps incorporate three cylinders pump on the forward stroke only while

duplex pumps consist of two cylinders and pump on both forward and backward strokes.

Triplex pumps are lighter and more compact than Duplex pumps and their output pressure

pulsations are not as great and are cheaper to operate.

Pumps are rated for hydraulic power, maximum pressure and maximum flowrate. We visited

John Energy 18 rig that had three triplex pumps of 1000 Hp each. Two of them were active and

one was on standby. The stroke length was 14 inch and pressure rating was 3000psi.

Different components and peripherals of the mud pumping system are as follows:

Suction line-Supercharger-gate valve-suction manifold-mud pump-discharge manifold-

pulsation dampener-pop off valve-crank shaft-diesel engine etc.


Page 45

Triplex Pumps

The piston discharges in only one direction, and so the rod diameter does not affect the pump

output. The discharge volume for one pump revolution is:

=3V1Ev=3πd2LEv/4

Again the pump output is found by multiplying by the pump speed:

Q=d2LEvR/98.03

Where,

Q=flow rate (gpm)

L = stroke length (in.)

d = liner diameter (in.)

R = pump speed (spm)

More power can be delivered using a triplex pump since higher pump speeds can be used.

Inside View Triplex Pump


Page 46

Pulsation Dampener:

Pulsation Dampeners utilize the compressibility of nitrogen gas for storing hydraulic

energy during pump compression. The nitrogen gas is compressed when the pulsation

dampener fills with mud from pump. When the pressure drops during the return cycle of

pump, the pulsation dampener steps in and uses its stored energy to dispense the stored fluid,

enabling a more constant flow pressure.

Supercharger:

Supercharger is a centrifugal pump that imparts a pressure around 300-400 psi to the

mud coming from the mud tank. This enables the mud pump to work at higher efficiencies.

There is gate valve after it, which ensures the flow to the suction line. Another gate valve is

used to bypass the flow directly to discharge line. The mud will be pumped by supercharger

when filling the casing while running and to fill the annulus when both the pumps fail.

Pop Off Valve:

It is a spring operated valve which has a pre-charged pressure dome (the pressure that

should not be exceeded or safety limit). If by some means the pressure generated by the pump

exceeds the pre-charged pressure the valve will release and mud will return to the mud tank

through a small return line. Pre-charged pressure was set at 2700 psi on JE-18 rig.

Pulsation Dampener


Page 47

High Pressure Line:

It transports the high pressure mud for pump to the standpipe. It had 15O2 hammer

union connection and the pressure rating was 5000 psi. The diameter of the line was 8 inches.

Mud Conditioning Equipments

Contamination of drilling fluids with drilled cuttings is an un-avoidable consequence of

successful drilling operations. If the drilling fluid does not carry cuttings to the surface, the rig

either is not making hole or soon will be stuck in the hole it is making.

Shale Shaker:

It is a series of trays with vibrating screens which allow the mud to pass through but retain the

cuttings. The mesh must be chosen carefully to match the size of the solids in the mud.

The other end of the flowline is directly connected to the possum belly, which act as a

distribution box to divide the flow to three shale shakers. The no. of shakers are decided by

the volume of cuttings being handled which depends upon the hole size.

Pop Off Valve


Page 48

JE 18 rig used MI SWACO Mongoose Pro shakers, each consisting of four screens. The three

motors mounted on the top of the screens impart lateral, transverse and elliptical vibrations;

this ensures maximum liquid removal from the surface of cuttings. The removed liquid falls in

the Sandtrap.

Screen size selection is the most important part of the shaker operation and it finds high

dependence on the formation we are drilling. Sandstones will generally produce finer cuttings

than the clay stones. For the bottom section of the well no. 21 JE 18 installed 140 mesh screens.

There was a gas trap sensor installed at the possum belly, which takes the mud along with

cuttings and churns the mud to separate out the gaseous fraction if any and the gas is then

sent to the mud logging unit for FID and gas chromatography. This is just a qualitative indication

of gas.

Degasser:

Degasser separates out the bulk amount of gas dissolved in mud. JE 18 used MI SWACO

Degasser; it uses a patented centrifugal force system rather than conventional vacuum or

impact systems. As such, the degasser exerts centrifugal force on the mud, multiplying the

force acting on the gas bubbles to increase buoyancy and release. The increased buoyancy

accelerates the bubble-rise velocity. As the bubbles rise toward the surface, they escape the

mud and are further broken down by flow turbulence. The gas is discharged at a safe distance

from the drilling operation while the restored mud is returned to the drilling fluid system.

Mud Cleaner:

Mud cleaner is a combined form of the desilter and desander. JE 18 uses 2-12 system

meaning 2 cones of desander and 12 cones of desilter. Desilter and desander are

hydrocyclones separators. Desilter has a lesser diameter than desander because it has to

remove finer particles. The capacity of individual desanders and desilters determine capacity

of mud cleaner. The 2-12 system has capacity of 1000 GPM. Lesser space occupied by the

system is the major advantage.

A centrifugal pump feeds mud tangentially at high speed into the housing, thus creating

high centrifugal forces. These forces multiply the settling rate so that the heavy particles are

thrown against the outer wall and descend towards the outlet (underflow).The lighter particles

move inwards and upwards as a spiralling vortex to the liquid discharge (overflow).


Page 49

Hydrocyclones are designed so that only solids (plus small volume of fluid) pass out the

underflow. This should appear as a “spray discharge” and not “rope discharge”. Rope

discharge is an indication of solids overloading, and the underflow will soon plug off

completely.

Mud Tanks and Mud mixing equipment:

Mud tanks are those in which mud is prepared, stored and fed to mud pumps. Basically a rig

has an active tank which feeds the mud to suction side of the pump. Intermediate tank is the

one where the returning mud from the solid control system is received, it is then sent to the

active tank. Reserve tanks are used for the storage of mud.

JE 18 rig had one active and intermediate tank each of 45m3 capacity and having

hemispherical base. Two reserve tanks were of 45m3 capacity each and two rectangular fresh

water tanks of 42m3 each.

Mud mixing involves mixing of base solvent either water or synthetic oil with different

types of additives. The solvent in the mud tank is constantly agitated by agitators while solid

particulate additives are poured through a hopper; it then passes a strainer to remove any kind

of debris and to break lumps of solid if any. Then a jet nozzle expels the solids to the suction

side of the blower, which pressurizes and sends it to mud tank.


Page 50

Well control systems:

Blowout preventer

Accumulator unit (consolidated pressure control)

accumilator bottles

reservoir tank

tubular manifold

prime electric pump

auxillary pneumatic pump

Choke manifold

ibop(as a part of the TDS)

Blowout preventer

A blowout preventer is a large, specialized valve or similar mechanical device, usually installed

redundantly in stacks, used to seal, control and monitor oil and gas wells. Blowout preventers

were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick)

emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic

event known as a blowout. In addition to controlling the downhole (occurring in the drilled

hole) pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing

(e.g. drill pipe and well casing), tools and drilling fluid from being blown out of

the wellbore (also known as bore hole, the hole leading to the reservoir) when a blowout

threatens. Blowout preventers are critical to the safety of crew, rig (the equipment system

used to drill a wellbore) and environment, and to the monitoring and maintenance of well

integrity; thus blowout preventers are intended to be fail-safe devices.

Types

BOPs come in two basic types, ram and annular. Both are often used together in drilling rig BOP

stacks, typically with at least one annular BOP capping a stack of several ram BOPs.

Ram blowout preventer

A ram-type BOP is similar in operation to a gate valve, but uses a pair of opposing steel

plungers, rams. The rams extend toward the center of the wellbore to restrict flow or retract

http://en.wikipedia.org/wiki/Drilling_rig


Page 51

open in order to permit flow. The inner and top faces of the rams are fitted with packers

(elastomeric seals) that press against each other, against the wellbore, and around tubing

running through the wellbore. Outlets at the sides of the BOP housing (body) are used for

connection to choke and kill lines or valves.

Rams, or ram blocks, are of four common types: pipe, blind, shear, and blind shear.

Pipe rams close around a drill pipe, restricting flow in the annulus (ring-shaped space between

concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct

flow within the drill pipe. Variable-bore pipe rams can accommodate tubing in a wider range

of outside diameters than standard pipe rams, but typically with some loss of pressure capacity

and longevity.

Blind rams (also known as sealing rams), which have no openings for tubing, can close off the

well when the well does not contain a drill string or other tubing, and seal it.

Shear rams cut through the drill string or casing with hardened steel shears.

Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended to seal a

wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as

the rams close off the well. The upper portion of the severed drill string is freed from the ram,

while the lower portion may be crimped and the “fish tail” captured to hang the drill string off

the BOP.

In addition to the standard ram functions, variable-bore pipe rams are frequently used as test

rams in a modified blowout preventer device known as a stack test valve. Stack test valves are

BOP STACK


Page 52

positioned at the bottom of a BOP stack and resist downward pressure (unlike BOPs, which

resist upward pressures). By closing the test ram and a BOP ram about the drillstring and

pressurizing the annulus, the BOP is pressure-tested for proper function.

Annular blowout preventer

An annular-type blowout preventer can close around the drill string, casing or a non-cylindrical

object, such as the kelly. Drill pipe including the larger-diameter tool joints (threaded

connectors) can be "stripped" (i.e., moved vertically while pressure is contained below)

through an annular preventer by careful control of the hydraulic closing pressure

An annular blowout preventer uses the principle of a wedge to shut in the wellbore. It has a

donut-like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs. The

original type of annular blowout preventer uses a “wedge-faced” (conical-faced) piston. As the

piston rises, vertical movement of the packing unit is restricted by the head and the sloped

face of the piston squeezes the packing unit inward, toward the center of the wellbore.

ACCUMULATOR UNIT

http://en.wikipedia.org/wiki/Kelly_drive

http://en.wikipedia.org/wiki/Wedge_(mechanical_device

http://en.wikipedia.org/wiki/Elastomer


Page 53

Well control equipments at RIG JOHN ENERGY 18(wrt rig specifications)

1 BOPS

1.Annular preventor a) Make Shaffer

b) Type annular flanged bottom

c) Rating 13 5/8 x 5000psi

2. Ram type Preventor a) Make Cameroon

b) Type U type

c) Rating 13 5/8 x 5000psi

2 BOP Control Unit a) Make CPC

b) Type

6 station with pnumetic and elctrical

pumps

c)No.of accumul. 24

Well control equipments at RIG WEATHERFORD 807(wrt rig specifications)


Page 54

SURFACE EQUIPMENTS

BOP CONTROL (RIG FLOOR) BOP CONTROL UNIT


Page 55

REFERENCES

Bourgoyne, A. T., Chenevert, M. E., Millheim, K. K., Young Jr., F. S. "Applied

Drilling Engineering", SPE Textbook Series: Volume 2.

Luo, Yuejin and P. A. Bern, BP Research Centre; and D. B.Chambers, BP

Exploration Co. Ltd. "Flow-Rate Predictions for Cleaning Deviated Wells."

IADC/SPE 23884.

Rabia, H. Rig Hydraulics. Entrac Software: Newcastle, England (1989):

Chapter 5.

Scott, K. F. "A New Approach to Drilling Hydraulics." Petroleum Engineer.

September 1972.

Documents

rig Hydraulics