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    CASING SETTING DEPTH AS PER GTO

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    TABLE OF CONTENTS

    Introduction

    Geo technical data

    Casing

    Casing shoe selection

    Casing specifications

    Casing considerations

    Conclusion

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    CHAPTER 1: INTRODUCTION

    The selection of casing setting depth is one of the most important tasks in preparing the well

    plan. Many aspects, such as lithology, overpressure formations, shallow gases, lost circulation

    and troublesome zones, directional well profiles and regulations should be considered in this

    selection. Recently, well control considerations have been included in this selection process

    through the application of the kick tolerance concept. It made the drilling execution safer and

    more economical. This motivated this study. Thus, the main objective of this paper is to discuss

    the effect of these well control considerations on the selection of casing shoe setting depth. The

    other aspects listed above will not be considered here.

    Kick tolerance can be understood as the capability of the wellbore to withstand the state of

    pressure generated during well control operations (well closure and subsequent gas kick

    circulation process) without fracturing the weakest formation. To account for the kick tolerance

    in the casing shoe setting depth selection, there important data are required:

    (1) The formation pressure at the final depth of the well phase,

    (2) The maximum kick volume that can be taken during the drilling operations

    (3) The fracture equivalent density curve for the area.

    With the total depth of a drilling phase set and the formation pressure at that depth known, the

    shallowest casing setting depth can be established considering the fracture equivalent density

    curve and pressure inside the wellbore during well control operations. This design process is

    called bottom-to-top method.

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    CHAPTER 2: GEO TECHNICAL DATA (LITHOLOGY)

    1. Narspuru clay &younger formations

    2. Nimmakuru sandstone formations

    3. Tirupati sandstone formations

    4. Raghavapuram shale formations

    5. Nandigama formations

    RecentEocene

    Recent: (surface 1400ft)

    Litho logy consist of strong sand with clay particles

    Narsapur group (0800ft)

    Litho logy

    Litho logy typically consist of black clay stone with sand stone .At the

    base which is over lain by thick sandstone and clays tone with minor amount of silt stone

    Naraspur group anticipated 800ft

    Sandstone Light black clear white ,pale yellow fine to medium grained i/p coarse grained,

    angular to sub angular unconsolidated to consolidated/p sorted calcareous cement micaceous

    Clays stone

    Medium to light black grey soft swell calcareous

    Siltstone:

    Reddish brown buff greenish grey calcareous cement

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    Narspuru group formations are clay and younger rocks in a bore hole drilling rate is good rate of

    penetration fast it harder formations they are supported to launch casing shoe

    .

    Nimmakuru group (800ft1400ft)

    Lithology

    Lithology typically consist of black sand stone with clay stone .At the base

    which is over lain by thick sandstone and clays tone with minor amount of silt stone

    Nimmakaur group anticipated 1400ft

    Sandstone

    Light black clear white ,pale yellow fine to medium grained i/p coarse grained, angular to sub

    angular unconsolidated to consolidated/p sorted calcareous cement micaceous

    Clays stone

    Medium to light black grey soft swell calcareous

    Siltstone

    Reddish brown buff greenish grey calcareous cement

    Nimmakuru group of formations are sandstone with minor amount of clay particles the drilling

    rate is better than narasupuru formations because softer formations this type of rocks not

    supported through any type casing due to cement raising problems

    Paleocene rzl formations

    Lithology typically consists of basalt

    Razolu group (1200ft -1400ft)

    Lithogy

    Razolu formations basalt highly poor rate of penetration

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    Drilling rate slow because harder formations and this type of formations not

    supported to casing shoe

    Upper cretaceous

    Tirupati group (1600ft -2350ft)

    Lithology typically consists of sandstone

    Lithology t he formation consists of medium grained sandstone. Conglomeratic in places and has

    Interbred of sandstone /clay stone

    Sandstone:

    Clear translucent light black fine to medium grained angular to sub rounded moderately sorted

    calcareous cement at type locality it is brown red purple or s shows lighter

    Shades of pink arkosic the pebble of the unit mostly of pink color and of quartzite

    Clay stone:

    Dark brown dark grey. Green reddish brown moderately hard to firm calcareous no swell,

    Tirupati sandstone formations are drilling rate good means rate of penetration more and this

    formations are softer formations and not suitable for casing shoe location

    Lower cretaceous

    Raghavapuram group (2350ft-3450ft)

    Lithology consist of shale formations

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    Lithology:

    Lower part of cretaceous shale formations is mainly composed of anhydrate

    Sandstone and clay stone while the beds of anhydrite siltstone coal and shale

    Clay stone:

    Off white grey reddish brown bluish grey i/p light grey i/p green i/p dark brown Argillaceous no

    swell silt calcareous

    Sandstone:

    Brown green black reddish brown dark brown i/p white to off white fine coarse grained angular

    sub rounded micasceous sorted calcareous to non calcareous cement silt brecciate with dolomite

    streaks

    Siltstone:

    White black dark brown to red dark grey friable to moderately hard

    Coal:

    black and dark brown to black and moderately hard material

    Anhydrite:

    White ,off white, green, soft to firm, i/p moderately hard i/p amorphous chalky.

    Salt:

    Clear occasionally translucent i/p pink hard to moderately hard

    Shale:

    Dark grey, black, firm, on calcareous,

    Raghavapuram shale formations drilling rate bad and rate of penetration slow this type of

    formations harder formations and they are supported the casing shoe the rop maximum 60min

    per meter drill pipe the drilling rate very slow it will time more to take

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    Lower Jurassic and lower cretaceous

    Nandigama group (3450ft-3910ft)

    The main object of drilling to reach nandigama formations safely these formations nothing but

    pay zone or reservoir zone

    Nandigama formations are mixed with different rock particles and determined how much crude

    oil in the surface or not it is producible are not

    Nandigama formations different stones sandstone clay stone siltstone and shale these rocks are

    mixed and identified more complex

    Sandstone:

    Purple to brown, yellowish brown, fine grained

    Clay stone:

    Reddish brown, non calcareous, non-swell, silt

    Siltstone:

    Reddish brown, off white, firm to hard, i/p dolomite

    Nandigama formations are drilling rate average and rate of penetration slow because of harder

    formations and supported casing shoe

    Nandigama formations thick reservoir beds they high temperature high pressure wells

    This type of formations are unstable and casing job do perfectly and in this zone may be came

    out of kick and pipe stacking problems arise

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    Formations will change mud parameters and bit parameters

    Clay stone and silt stone sandstone shale formations occurs to high mud losses in bore hole

    In order to resolve this problems following methods

    1. Increase mud weight

    2. Saddest

    3. Groundnuts

    4. Carry bags

    After geo technical data consideration to prepare drilling program

    THE DRILLING PROPOSAL AND DRILLING PROGRAM

    The proposal for drilling the well is prepared by the geologists and reservoir engineers in the

    operating company and provides the information upon which the well will be designed and

    the drilling program will be prepared. The proposal contains the following information:

    Objective of the Well

    Depth (m/ft Subsea), and Location (Longitude and Latitude) of Target

    Geological Cross section

    Pore Pressure Profile Prediction

    The drilling program is prepared by the Drilling Engineer and contains the following:

    Drilling Rig to be used for the well

    Proposed Location for the Drilling Rig

    Hole Sizes and Depths

    Casing Sizes and Depths

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    Drilling Fluid Specification

    Directional Drilling Information

    Well Control Equipment and Procedures

    Bits and Hydraulics Program

    .

    Drilling and Casing the 23 Hole:

    They installing 185/8 conductor casing first casing of the well

    The first stage in the operation is to drive a large diameter pipe to a depth of approximately 100ft

    below ground level using a truck mounted pile-driver. This pipe (usually called casing or, in the

    case of the first pipe installed, the conductor) is installed to prevent the unconsolidated surface

    formations from collapsing whilst drilling deeper.

    The first whole section is drilled with a drill bit, which has a smaller diameter than the inner

    diameter (I.D) of the conductor. Since the I.D. of the conductor is approximately diameter bit is

    generally used for this whole section. This 23" hole will be drilled down through the

    unconsolidated formations, near surface, to approximately 2000'. If possible, the entire well,

    from surface to the reservoir would be drilled in one hole section. However, this is generally not

    possible because of geological and formation pressure problems which are encountered whilst

    drilling. The well is therefore drilled in sections, with casing being used to isolate the problem

    formations once they have been penetrated. This means however that the wellbore diameter gets

    smaller and smaller as the well goes deeper and deeper. The drilling engineer must assess the

    risk of encountering these problems, on the basis of the geological and formation pressure

    information provided by the geologists and reservoir engineers, and drilling experience in the

    area. The well will then be designed such that the dimensions of the borehole that penetrates the

    reservoir, and the casing that is set across the reservoir, will allow the well to be produced in the

    most efficient manner possible. In the case of an exploration well the final borehole diameter

    must be large enough to allow the reservoir to be fully evaluated.

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    Whilst drilling the 23 hole, drilling fluid (mud)is circulated down the drill pipe, across the face

    of the drill bit, and up the annulus between the drill pipe and the borehole, carrying the drilled

    cuttings from the face of the bit to surface. At surface the cuttings are removed from the mud

    before it is circulated back down the drill pipe, to collect more cuttings.

    When the drill bit reaches approximately 2000 the drill string is pulled out of the hole and

    another string of pipe (surface casing)is run into the hole. This casing, which is generally 20"

    O.D., is delivered to the rig in 40ft lengths (joints) with threaded connections at either end of

    each joint. The casing is lowered into the hole, joint by joint, until it reaches the bottom of the

    hole. Cement slurry is then pumped into the annular space between the casing and the borehole.

    This cement sheath acts as a seal between the casing and the borehole, preventing carvings from

    falling down through the annular space between the casing and hole, into the subsequent hole

    and/or fluids fl owing from the next hole section up into this annular space.

    Drilling and Casing the 17 1/2 Hole:

    Once the cement has set hard, a large spool called a wellhead housing is attached to the top of

    the 20 casing. This wellhead housing is used to support the weight of sub sequent casing strings

    and the annular valves known as the Blowout prevention(BOP) stack which must be placed on

    top of the casing before the next hole section is drilled.

    Since it is possible that formations containing fluids under high pressure will be encountered

    whilst drilling the next (17 1/2) hole section a set of valves, known as a Blowout prevention

    (BOP) stack, is generally fitted to the wellhead before the 17 1/2 hole section is started. If high

    pressure fluids are encountered they will displace the drilling mud and, if the BOP stack were not

    in place, would flow in an uncontrolled manner to surface. This uncontrolled flow of

    hydrocarbons is termed a Blowout and hence the title Blowout Preventers (BOPs). The BOP

    valves are designed to close around the drill pipe, sealing off the annular space between the drill

    pipe and the casing. These BOPS have a large I.D. so that all of the necessary drilling tools can

    be run in hole.

    When the BOPs have been installed and pressure tested, a 17 1/2" hole is drilled down to 6000

    ft. Once this depth has been reached the troublesome formations in the 17 1/2" hole are isolated

    behind another string of casing (13 5/8" intermediate casing). This casing is run into the hole in

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    the same way as the 20 casing and is supported by the 20 wellhead housing whilst it is

    cemented in place.

    When the cement has set hard the BOP stack is removed and a wellhead spool is mounted on top

    of the wellhead housing. The wellhead spool performs the same function as wellhead housing

    except that the wellhead spool has a spool connection on its upper and lower end whereas the

    wellhead housing has a threaded or welded connection on its lower end and a spool connection

    on its upper end. This wellhead spool supports the weight of the next string of casing and the

    BOP stack which is required for the next hole section.

    Drilling and Casing the 12 1/4 Hole:

    When the BOP has been re-installed and pressure tested a 12 1/4" hole is drilled through the oil

    bearing reservoir. Whilst drilling through this formation oil will be visible on the cuttings being

    brought to surface by the drilling fluid. If gas is present in the formation it will also be brought to

    surface by the drilling fluid and detected by gas detectors placed above the mud flow line

    connected to the top of the BOP stack. If oil or gas is detected the formation will be evaluated

    more fully.

    The drill string is pulled out and tools which can measure for instance: the electrical resistance of

    the fluids in the rock (indicating the presence of water or hydrocarbons); the bulk density of the

    rock (indicating the porosity of the rocks); or the natural radioactive emissions from the rock

    (indicating the presence of non-porous shalesor porous sands) are run in hole. These tools are

    run on conductive cable called electric wire line,so that the measurements can be transmitted

    and plotted (against depth) almost immediately at surface. These plots are called Petro physical

    logs and the tools are therefore called wire line logging tools.

    In some cases, it may be desirable to retrieve a large cylindrical sample of the rock known as

    a core. In order to do this the conventional bit must be pulled from the borehole when theconventional drill bit is about to enter the oil-bearing sand. A donut shaped bit is then attached a

    special large diameter pipe known as a core barrel is run in hole on the drill pipe.

    This coring assembly allows the core to be cut from the rock and retrieved. Porosity and

    permeability measurements can be conducted on this core sample in the laboratory.

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    In some cases tools will be run in the hole which will allow the hydrocarbons in the sand to flow

    to surface in a controlled manner. These tools allow the fluid to flow in much the same way as it

    would when the well is on production. Since the produced fluid is allowed to flow through the

    drill string or, as it is sometimes called, the drilling string, this test is termed a drill-stem test or

    DST.

    If all the indications from these tests are good then the oil company will decide to complete the

    well. If the tests are negative or show only slight indications of oil, the well will be abandoned.

    Completing the Well:

    If the well is to be used for long term production, equipment which will allow the controlled flow

    of the hydrocarbons must be installed in the well. In most cases the first step in this operation is

    to run and cement production casing (9 5/8" O.D.) across the oil producing zone. A string of

    pipe, known as tubing (4 1/2" O.D.), through which the hydrocarbons will flow is then run

    inside this casing string. The production tubing, unlike the production casing, can be pulled from

    the well if it develops a leak or corrodes. The annulus between the production casing and the

    production tubing is sealed off by a device known as a packer. This device is run on the bottom

    of the tubing and is set in place by hydraulic pressure or mechanical manipulation of the tubing

    string.

    When the packer is positioned just above the pay zone its rubber seals are expanded to seal off

    the annulus between the tubing and the 9 5/8" casing. The BOPs are then removed and a set of

    valves (Christmastree)is installed on the top of the wellhead. The Xmas tress is used to control

    the flow of oil once it reaches the surface. To initiate production, the production casing is

    perforatedby explosive charges run down the tubing on wire line and positioned adjacent to

    the pay zone. Holes are then shot through the casing and cement into the formation. The

    hydrocarbons flow into the wellbore and up the tubing to the surface.

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    CHAPTER 3: CASING SHOE SELECTION

    CASING SETTING DEPTH

    Casing and its functions:

    At a certain stage during the drilling of oil and gas wells, it becomes necessary to line the walls

    of a borehole with steel pipe which is called Casing. Casing serves numerous purposes during

    the drilling and production history of oil and gas wells, these include:

    1. Keeping the hole open by preventing the weak formations from collapsing. i.e., caving of the

    hole.

    2. Serving as a high strength flow conduit to surface for both drilling and production fluids.

    3. Protecting the freshwater-bearing formations from contamination by drilling and production

    fluids.

    4. Providing a suitable support for wellhead equipment and blowout preventers for controlling

    subsurface pressure, and for the installation of tubing and subsurface equipment.

    5. Providing safe passage for running wire line equipment

    5.

    Allowing isolated communication with selectively perforated formations of interest.

    Casing Setting Depth Criteria

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    The general criteria for the selection of casing shoe setting depths is that hole section should be

    drilled successfully and safely at minimum cost. The casing shoe is normally set in competent

    formation which should be able to withstand the forces imposed upon it during well activity.

    Methodology of Casing Seat Selection:

    The mechanism for selecting casing setting depth is as follows:

    1) The well objective is clearly defined.

    2) Actual and any potential problems encountered in nearby wells are listed.

    3) The pore and fracture pressure profile is overlaid against the litho logical column,

    potential troublesome zones and the hydrocarbon bearing zones.

    4) Production casing shoe depth requirements are studied and suitable formation and depth

    are selected so as to meet these requirements as an absolute minimum.

    5) Intermediate casing shoe depth requirements are studied to satisfy designed kick

    tolerance and the differential pressure consideration and a suitable casing point is selected

    to meet these requirements as an absolute minimum.

    6) Kick tolerance and the maximum differential pressure are recalculated for the selected

    seat.

    Estimation of fracture pressure with respect to LOT

    Formation fracture pressure or formation breakdown pressure is the pressure required to rupture

    a formation, so that whole mud can flow into it.

    Commonly this is expressed as a pressure gradient, GFB, with the units of psi/foot. The formation

    breakdown pressure is usually determined for formations just below a casing shoe by means of a

    leak-off test. This test of the formation strength, also known as a formation integrity test or FIT,

    is affected after the casing has been run and cemented in place. This allows formations to be

    tested after the minimum of disturbance and damage due to drilling, and allows a clear indication

    of strength to be determined for one isolated zone.

    The general procedure for a leak-off test is as follows:

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    Casing is run and cemented in place. The cement is allowed to harden before testing takes

    place, to prevent the formation of micro-annuli between cement and casing after the

    casing expands under pressure.

    The shoe and cement is drilled out, and five to ten feet of new formation is drilled. Some

    companies will drill as much as 20 ft of new formation.

    The bit is pulled to the shoe and the hole circulated clean, with balanced mud weight in

    and out.

    The well is closed in using the blowout preventers, and a chiksan line to the cement unit

    made up on the drill pipe. The cement unit pump is used because it is a high pressure, low

    volume pump and small volume can be accurately measured using the cement unit.

    With the well closed in, the cement pump is used to pump a small volume at a time into

    the hole (typically or a barrel each time). Since this is being pumped into a closed

    well, the pressure in the well rises. So long as the system remains closed and nothing

    breaks, the pressure increase for each volume pumped will be the same. A graph of well

    pressure versus volume pumped will show a near straight line until a break occurs. At this

    point fluid is being injected into the formation and the pressure rise will be smaller.

    Further pumping will not necessarily show a pressure rise but more commonly a pressure

    drop.

    Figure shows a typical graph for a leak-off test carried out in this way. Here mud has been

    pumped slowly in quarter-barrel amounts. After each quarter barrel, the pump is shut down and

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    pressure allowed stabilizing for 30 seconds or so. This value is noted on the graph and pumping

    continued.

    Some companies graph both pumping and static pressures. The two lines should run

    approximately parallel until breakdown occurs, at which point they diverge.

    The leak-off pressure, PLO, determined by this test is the surface pressure which when added to

    the hydrostatic head of mud in the Well causes formation breakdown.

    Thus:

    Formation Breakdown pressure = Hydrostatic Pressure of Mud to Shoe Pressure + Leak-Off

    Pressure

    PFB= HMUD+ PLO

    Note that, this is the full leak-off procedure which is used, for example on exploration, wildcat

    and possibly some development wells. A full leak-off test is not often carried out on Production

    Wells. A proofing or integrity test is carried out to demonstrate that the casing shoe can hold

    the pressure exerted by the maximum weight to be run in the next section, plus a safety factor.

    Casing Seat Selection

    Selecting casing setting depths for each casing string to be run in a well is often the most critical

    decision made in pre-planning; especially where abnormal pressures or weak, lost circulation

    zones, are expected.

    The key to satisfactory casing seat selection is the assessment of pore pressure (formation fluid

    pressures) and fracture pressures throughout the well. Evidently, as the pore pressure in a

    formation being drilled approaches the fracture pressure at the last casing seat then a further

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    string of casing is necessary. Figure illustrates this, with an idealized casing seat selection

    shown.

    Casing is set at Depth 1, where pore pressure is P1 and the fracture pressure is F1. Drilling

    continues to Depth 2, where the pore pressure P2 has risen to almost equal the fracture pressure

    (F1) at the first casing seat. Another casing string is therefore set at this depth, with fracture

    pressure (F2). Drilling can thus continue to Depth 3, where pore pressure (P3) is almost equal to

    the fracture pressure F2 at the previous casing seat.

    Procedure to Determine Casing Shoe Depth:

    A graph is plotted between Depth and Specific Gravity.

    Fracture Pressure line is plotted with the help of fracture pressure data (LOT/PIT data

    from the nearby wells).

    Formation Pressure line is plotted from the data given in GTO.

    Mud wt. line is plotted (assuming 0.1 SG greater than formation pressure which includes

    surge factor, swab factor and safety factor).

    Again considered 0.1 safety factor from Mud weight, draw a vertical line. The line where

    it crosses the LOT curve represents the maximum limit for section of casing depth. So

    always casing should be taken below the intersecting point on the curve and not to keep

    at a shallower depth.

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    In this process we have to consider and take care of open hole conditions, water baring

    zone at shallow depths, gas influx and HC presence. If any of the above features are

    identified while drilling then the casing should be selected few meters above of those

    zones.

    Casing Shoe Selections

    Common practice today is usually to choose casing shoe setting depth based on the drilling

    Process. Selection of casing shoe depth may have different optimal solutions for drilling and

    Production.

    Well Design

    When drilling of a new well is planned it is advantageous to know the pore pressure- and

    Fracture gradient of the formation. These data can be obtained from for example nearby

    already drilled wells. Knowing the pressure and fracture profile a mud window, as shown in

    Graph, can be made. In the diagram the gradients are plotted versus depth. Based on

    These data a program of bit sizes, casing sizes, steel grades and setting depth can be made.

    Because of economic reasons casing strings can be made up of different steel grades, wall

    Thickness and coupling types. The potential savings of selecting different steel grades in

    Sections of the casing must be considered against additional risks. These risks are associated

    With performance of leak free tieback operations and additional wear resulting from longer

    Exposure of the upper casing to rotation and translation of the drill string

    The combination of different steel grades may also have an important saying in how well the

    Well resists SCP. In this thesis the aim is to find out how the setting depth influences the

    occurrence of SCP. The main focus will therefore be on selection of the setting depth and not

    on how different weight, grade and coupling types for the casing are chosen. If the well is

    drilled underbalanced the collapse pressure also has to be taken into consideration, this is

    also not included in the problem to be addressed in this thesis.

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    Setting Depth Based on mud weight

    Deciding the setting depth of a casing string a number of elements has to be taken into

    Consideration. Calculations are made to see whether the casing can take loads occurring

    During a kick or underground blowout.

    First step is to design a casing program based on mud weight. A safety margin of 0.5 ppg is

    commonly used for both pore pressure and fracture gradient to ensure a safe operation without

    kicks and fracturing of the formation. A trip margin of 0.5 ppg is plotted in graph with dashed

    lines. The setting depth has a strong correlation with the mud density used to drill a section. As

    the well is drilled, the pore pressure is increasing and the pressure difference between mud

    gradient end pore pressure gradient is 5 ppg decreasing. To prevent the two gradient lines from

    crossing and avoiding a kick the casing shoe is set and the mud weight is increased.

    Casing size (in.) Depth (ft.)

    7 3450

    9 5/8 2450

    13 3/8 1700

    18 5/8 500

    When the setting depth based on mud weight is found, the kick criterion may to be taken

    into consideration. Some changes probably have to be done to the casing setting depths to

    Satisfy the new criterion

    When the setting depth based on mud weight is found, the kick criterion may to be taken

    into consideration. Some changes probably have to be done to the casing setting depths to

    Satisfy the new criterion

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    Setting Depth Based on Kick Criterion

    During drilling kicks from high pressure formations may be passed on the way to the

    Reservoir if the mud pressure cannot withstand the pressure from the formation, a kick may

    Occur. By taking the kick criterion into consideration, the setting depth may be chosen so

    that the formation in which the casing is set can withstand the pressure it is exposed to

    during the kick.

    Using this method it is important to do the evaluation based on pressure and not the

    Pressure gradients Pore pressure and fracture pressure are therefore plotted

    in psi versus depth. An example of pore pressure versus depth is shown in graph If the well has

    been drilled to 4000m and a kick takes place it should be designed to

    handle this. Assuming the formation fluid at this depth is a condensate with density 4.58 ppg

    Constant density and no expansion during circulation. When the kick takes place

    the well will be filled with condensate and the pressure upward in the well will be reduced

    by the weight of this fluid graph the kick fluid gradient is plotted. The point where it crosses the

    fracture Pressure line indicates the new casing setting depth. Repeating this gives the other

    casing setting depths. Graph shows where the new setting depths have to be to satisfy the kick

    criteria.

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    Leak-off Test

    The leak-off test is an important factor when the well integrity is evaluated. It is usually

    Performed after a casing shoe is set to make sure the shoe and casing are fulfilling the

    requirements to well integrity.

    Leak-off tests can be used to estimate the maximum pressure a casing shoe can withstand.

    Knowing this value, the maximum mud weight that can be used to drill the next section can

    be calculated .To make sure the cement and formation below the casing

    shoe can withstand the pressure exerted on them during drilling of the next section, they

    may also be leak-off tested

    The LOT is performed by closing the well at the surface and increasing the well pressure by

    pumping with a constant rate. The pumping is stopped when the test pressure is reached or

    the injection pressure starts to divert from the trend line. Figure 4.5 shows a typical leak-off

    test.

    0

    500

    1000

    1500

    2000

    2500

    3000

    3500

    4000

    0 1 2 3 4

    pore pressure

    normal pressure

    kill pressure

    fracture gradient

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    Because of the

    constant pump rate, a plot of injection pressure versus pump rate will give a

    relatively straight line up to point A as seen in graph. At point A the formation grains

    are starting to move apart allowing mud to flow into the formation. Because mud is escaping

    the wellbore the injection pressure is decreasing and starts to divert from the trend line. The

    pressure that can be read at point A is called the Leak-Off Pressure (LOP) and is used to

    calculate the formation fracture gradient.

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    To make sure the fracture pressure has been reached, the pump is not turned off before

    point B is reached. After point B the pressure decrease is plotted versus time instead of

    pump rate. The rate at which the pressure decreases may tell something about the mud flow

    From the well into the formation

    A leak-off test is quite harmful and may leave the well in a worse condition than it was

    before the test was carried out .When it is really necessary to know how far it is possible to

    drill into the next formation the LOT may be used.

    Because regular LOT may vary in accuracy, the need for a more precise method led to the

    development of the extended leak-off test.

    Formation Integrity Test (FIT) and Leak Off Test (LOT), are two methods to determine:1.

    Strength of cement around the casing shoe after setting.2. Approximate the fracture gradient, later will

    be use to create mud programs.3. To determine the current Maximum Allowable Annular Surface

    Pressure(MAASP) well control event.LOT and FIT in principle the same, by pumping mud

    without circulation to the surface. (BOP closed, the choke closed). LOT is usually done on

    exploration wells, and FIT is usually done on the well development (because the value of fracture

    pressure be expected from well data neighbors who've done a LOT)

    Leak off test in equivalent mud weight (ppg) = (Leak off test pressure in psi) 0.052 (Casing

    Shoe TVD in ft) + (current mud weight in ppg)

    Pressure gradient in psi/ft = (Leak off test pressure in psi) (Casing Shoe TVD in ft)

    Formation integrity test

    Formation Integrity Test is the method to test strength of formation and shoe by increasing

    Bottom Hole Pressure (BHP) to designed pressure. FIT is normally conducted to ensure that

    formation below show will not be broken while drilling the next section with higher BHP.

    Normally, engineers in town will design how much formation integrity test pressure required

    mostly in ppg

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    Before forming formation integrity test, you should know pressure required for Formation

    Integrity Test. The formula showed below demonstrates you how to calculate required FIT

    pressure

    Pressure required for fit (psi) = (required fit in ppg- current mud weight)(0.052)(true vertical

    depth in shoe ft)

    Fit values guide to follow

    1. Drill out new formation few feet, circulate bottom up and collect sample to confirm that new

    formation is drilled to and then pull string into the casing.

    2. Close annular preventer or pipe rams, line up a pump, normally a cement pump, and circulate

    through an open choke line to ensure that surface line is fully filled with drilling fluid.3.

    3. Gradually pump small amount of drilling fluid into well with constant pump stroke. Record

    total pump strokes, drill pipe pressure and casing pressure. Pump until casing pressure reaches

    the pressure required for formation integrity test. Hold pressure for few minutes to confirm

    pressure.

    4. Bleed off pressure and open up the well. Then precede drilling operation.

    Creating mud program

    Basic principles in making mud program are as follows:

    1. Determine the pore pressure and fracture pressure along the depth that we will drill. Some also

    stressed the need for a data field minimum stress and overburden. Such data can be obtainedfrom measurements at the nearest drill wells that we will drill. The data can be obtained directly

    from measurements (PWD-pressure while drilling) or of the processed D-exponent correction (a

    function of ROP, RPM, WOB, bit diameter). If the well is the first well to be drilled / exploration

    (no data from nearby wells), the data can be estimated by converting sonic travel time of the

    seismic survey.

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    2. Once we have a pore pressure vs. depth plot and fracture pressure, we can determine casing

    setting depth and mud weight (density). In normal drilling (overbalance), we design the best

    possible mud weight greater than the pore pressure (so as not to kick) but smaller than the

    fracture pressure (so that no formation fracturing).

    3. Determine what type of mud that will be based on lithologic formations penetrated. There are

    three general categories of types of mud, the water-based mud (for wells with simple trajectories,

    no reactive shale), oil-based mud (for wells with more complex trajectories, many reactive shale

    zone), synthetic based mud (OBM has similar properties but more environmental friendly).

    4. Designing Rheology (viscosity, yield point, gel strength) and mud additive required under

    circumstances that will be penetrated lithologic, avoid formation damage while drilling the

    reservoir zone, reducing the thickness of the mud cake, or other specific purposes. It can be

    consulted with mud representative company.

    5. After step 2, 3, and 4 then need to count how much pressure loss when the mud that we design

    circulated during drilling. Then we calculate the ECD as mud hydrostatic pressure + pressure

    loss. ECD (equivalent circulating density), we compare it to the plot in step 2. ECD must live

    between pore pressure and fracture pressure. Often added to the calculation / density margin to

    avoid differential pipe sticking, surge effects, swab effect, etc

    6. Optimization of hydraulic mud. Using data from a mud drilling program to determine other

    parameters (pump rate, pump pressure, bit nozzle area, etc.) to get that optimum drilling

    performance.

    7. Iterations of the above steps until all criteria is reached with the optimum

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    CHAPTER 4: TYPES OF CASINGS

    TYPES OF CASINGS

    Casing Types: Casing is usually divided into five basic types.

    Conductor Casing

    Conductor pipe or drive pipe if it is hammer-driven to depth is the first string of casing to be

    used. The setting depth can vary from 10 ft to around 300 ft. The normal size range for conductor

    pipe is from 16 to 36 inches (outside diameter). The conductor pipe must be large enough to

    allow the other casing strings to be run through it. Purposes of conductor pipe are to:

    It prevents erosions due to the unconsolidated nature of formations

    Raise the level of circulating fluid so that fluid returns are possible

    It is the largest diameter of casing used in a well and is required only where the surface soils are

    incompetent due to the washing and eroding action of the drilling mud and a large cavity is

    created at the surface. Conductor casing controls this erosion of the surface formations.

    To estimate the anticipated fracture pressure, the following conditions must be considered:

    Drilling rate with loading effect in annulus

    Equivalent circulating density

    Mud weight to be used.

    Surface Casing

    The amount of surface casing used will depend on the depth of the unconsolidated formations.

    Surface casing is usually set in the first competent formation. Normal size for surface casing is

    between 20 inch and 13-3/8 inch (outside diameter). Since temperature, pressure and corrosive

    fluids tend to increase with depth different grades of casing will be required to handle the

    different well conditions. Purposes of surface casing are to:

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    Protect fresh water formations

    Seal off unconsolidated formations and lost circulation zones

    Provide a place to install the B.O.P.'s

    Maintain hole integrity by preventing caving

    Minimize lost circulation into shallow, permeable zones

    Surface casing is treated as conductor casing if no hydrocarbons are expected in the next hole

    interval or alternatively as intermediate casing in the event that hydrocarbons are expected in the

    next phase of drilling

    Intermediate Casing

    Intermediate casing is set after surface casing, normally to seal off a problem formation. The size

    of intermediate casing will depend on the size of the surface casing and the grade required

    withstanding the subsurface conditions. Normal sizes are between 9 5/8 and 13 3/8 inch (outside

    diameter).

    Depending upon the depth of the well and the anticipated problems in drilling the well, such as

    abnormal pressure formations heaving formations or lost circulation zones, it may be necessary

    to set a number of intermediate strings of casing to seal off the long open hole or zones causing

    trouble.

    The shoe selected for intermediate casing should be strong enough to withstand fracture during

    drilling the next hole section and should be able to take a kick of predefined size. Other major

    considerations for selection of intermediate casing seat are:

    Differential pressure consideration for safe lowering of the casing

    Isolation of troublesome or unstable formations which may include heaving shales, loss

    circulation zones, flowing halitesetc.

    Length of open hole.

    Liner

    A liner is a string of casing that does not reach the surface. They are usually hung (attached to

    the intermediate casing using an arrangement of packers and slips) from the bottom of the

    intermediate casing and reach to the bottom of the hole. The major advantage of a liner is the

    cost of the string is reduced, as are running and cementing times. During the course of the well,

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    if the liner has to be extended to the surface (making it another string of casing), the string

    attaching the liner to the surface is known as a tie-back string.

    Unlike casing, liner is used from the bottom of the hole to a shallower depth inside the previous

    casing with about 100-150 m overlap between the two strings. In this case, since the intermediate

    casing is exposed to same drilling condition as the liner, it must be evaluated with respect to

    burst and collapse pressure for drilling the open hole below the liner.

    Production Casing

    Production casing is usually the last full string of pipe set in a well. These strings are run to

    isolate producing formations and provide for selective production in multi-zone production areas.

    The size of production casing will depend on the expected production rate, the higher the barrel

    per day production rate, the larger the inside diameter of the pipe. Common sizes are between 3

    and 7 inch (outside diameter).

    The production casing is often called oil string. The production casing is lowered for the

    following purposes:

    Isolate the producing zone from the other formations.

    Protect the production tubing and other equipment.

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    CHAPTER 5: CASING SPECIFICATIONS

    CASING SPECIFICATION

    Casings are specified according to following

    Size

    Size is specified by outside diameter of the casing pipe. API SPEC-5A furnishes the full details

    of tolerance on outside diameter and weight. API tolerance on outside diameter for non-upset

    casings are 0.031 inch for 4" and smaller and 0.75% for 4.5" and larger size. The API

    tolerance on wall thickness is -12.5 %.

    Nominal Weight

    The term nominal weight is primarily used for the purpose of identification of casing type during

    ordering. It is expressed in ppf or kg/m. Nominal weight is not the exact weight and is

    approximately equal to the calculated theoretical weight per foot for a 20 feet (6.1 m) length of

    threaded and coupled casing joint.

    Plain End Weight

    The plain end weight of the casing joint is the weight without the inclusion of thread and

    coupling. It can be calculated from the following formula:

    Wpe= 10.68 (D-t) t ppf or Wpe= 0.02466 (D-t) t kg/m

    Where,

    Wpe = Plain end weight (ppf or kg/m)

    D = Diameter (inch or mm)

    t = Wall thickness (inch or mm)

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    Grade of Steel:

    Casing Standards

    The American Petroleum Institute (API) has developed certain standards and specifications for

    oil-field related casing and tubing. One of the more common standards is weight per unit length.

    There are three weights used:

    Nominal Weight: Based on the theoretical calculated weight per foot for a 20 ft length of

    threaded and coupled casing joint.

    Plain End Weight: The weight of the joint of casing without the threads and couplings.

    Threaded and Coupled Weight: The weight of a casing joint with threads on both ends

    and a coupling at one end.

    The Plain End Weight, and the Threaded and Coupled Weight are calculated using API formulas.

    These can be found in API Bulletin 5C3. API standards include three length ranges, which are:

    R-1: Joint length must be within the range of 16 to 25 feet, and 95% must have lengths

    greater than 18 feet

    R-2: Joint length must be within the range of 25 to 34 feet, and 95% must have lengths

    greater than 28 feet

    R-3: Joint length must be over 34 feet, and 95% must have lengths greater than 36 feet.

    The API grade of casing denotes the steel properties of the casing. The grade has a letter, which

    designates the grade, and a number, which designates the minimum yield strength in thousands

    of psi.

    The raw material used for manufacturing of casing has no definite microstructure. The

    microstructure of steel and mechanical properties can be greatly changed by the addition of

    special alloys and by heat treatment. Thus, different grades of casing can be manufactured to suit

    different drilling situations. The number designates the minimum yield strength of that particular

    grade in thousands of psi. The minimum yield strength is defined as the tensile stress required on

    a test specimen to produce the following extension under load as determined by an extensometer.

    A table of API casing grades and properties are listed below:

    API

    Steel Grade

    Min.Yield

    Strength(psi)

    Min.Tensile

    Strength(psi)

    % elongation for min.

    yield strength

    H-40 40,000 60,000 0.5

    J-55 55,000 75,000 0.5

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    K-55 55,000 95,000 0.5

    C-75 75,000 95,000 0.5

    L-80 80,000 1,00,000 0.5

    N-80 80,000 1,00,000 0.5

    C-90 90,000 1,05,000 0.5

    C-95 95,000 1,05,000 0.5

    P-110 1,10,000 1,25,000 0.6

    Q-125 1,25,000 1,35,000 0.65

    In addition to API grades, several other proprietary steel grades called as non-API grades are

    widely used in oil industry.

    Casing strength properties

    Casing pipe strength properties are generally specified as:

    (1) Yield strength for

    (a) Pipe body and

    (b) Coupling

    (2) Collapse strength for pipe body

    (3) Burst strength for (a) pipe body,

    (b) Coupling and

    (c) Leak resistance of the connection.

    Casing dimensions are specified by its outside diameter (OD) and nominal wall thickness.

    Normal well site conventions specify casing by its OD and weight per foot. As stated earlier, one

    should specify which weight one is referring to, though most often it is the nominal weight.

    1. Yield strength:

    a. Pipe body yield strength

    b. Coupling strength

    API defined the yield strength as the tensile stress required to produce 0.5% of the gauge

    length

    Most common types of casing joints are threaded on both ends and fitted with a threaded

    coupling on one end only

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    Joint strength may be lower or higher than the main casing, pipe body yield

    There are integral casing without coupling in which the threads are cut from internal-

    external upset

    2. Collapse strength:

    Defined as the maximum external pressure required collapsing specimen of casing

    3. Burst strength:

    a. Plain end

    b. Coupling

    It is defined as the maximum value of internal pressure required causing the steel to yield.

    CASING SPECIFICATIONS

    Factors influencing casing design:

    Casing design is influenced by:

    (a) Loading conditions during drilling and production.

    (b) Formation strength at casing shoe.

    (c) The degree of deterioration to which the pipe will be subjected during entire life of a well.

    DESIGN CRITERIA

    The following are the criteria which must be considered when carrying out detailed casingdesign:

    (1) Axial load

    (a) Axial tension

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    (b) Axial compression

    (2) Collapse pressure

    (3) Burst pressure

    (4) Other loading conditions, if any

    (1) AXIAL LOAD

    (a) AXIAL TENSION

    Most axial tension arises from the weight of casing itself. Other tension loadings can arise due to

    bending, drag, shock loading and pressure testing of casing.

    Pressure testingwill be performed on the casing as the plugs are bumped and later on in the

    well depending on operational conditions. The actual test pressure will depend on:

    * The rated burst strength of the casing.

    * The well head pressure rating.

    * The BOP stacks pressure rating.

    * The maximum anticipated surface pressure.

    (b) AXIAL COMPRESSION

    Compression effects occur in casing due to temperature effects in landed casing and because ofthe weight of other inner casing strings which are supported by the outer strings.

    So far as compression loads are concerned, wells fall into one of three categories:

    (1) Land wells and subsea wells

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    (2) Platform wells with surface wellheads

    (3) Mud line suspension wells

    In land wells, if the outer casing is cemented all the way to surface it will be able to support allthe expected compression loads. If, however, it is not cemented to surface, then there is danger of

    buckling due to the compressive loads.

    In platform wells, with surface wellheads, there is free standing part of the casing equivalent to

    the water depth plus air gap plus height to the wellhead deck. Buckling can occur on this free

    standing section. To prevent buckling, the outermost casing must be well centralized within the

    conductor and designed to be strong enough to withstand the likely buckling forces.

    With mud line suspension wells, used mostly on jack-up wells, the weight of the casing is hung

    off at the seabed. The tieback string which links the seabed wellhead with the surface equipment

    on the jack up rigs is however, subject to buckling.

    During drilling operations, in most of the cases, the temperature effect is so slight that it can be

    ignored. However, during the production phase, the compressive loads on the production string

    must be considered.

    COLLAPSE PRESSURE

    Collapse pressure originates from the mud column behind the casing. Since mud hydrostatic

    pressure increases with depth, collapse pressure will be maximum at bottom and zero at top.

    When a casing is subjected to a collapse pressure due to mud hydrostatic pressure from outside,

    it is called collapse Load. The internal pressure (due to any reason) is called back up. The

    difference between the collapse and internal pressure is termed as resultant. Resultant is the net

    pressure which is actually acting on the casing.

    If the casing is designed in collapse as total empty from inside, it is known as dry design. In this

    case back up equals to zero. Normally a surface casing is designed dry and intermediate casing is

    designed partially empty assuming that the casing shoe will be able to withstand minimum of

    native fluid column.

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    BURST PRESSURE

    The burst criterion in casing design is normally based on the maximum internal pressure

    resulting from a kick during drilling of the next hole section. For added safety in some cases, it is

    also assumed that influx fluid will displace the entire mud, thereby subjecting the inside of the

    casing to the bursting effects of formation pressure. The "load", "back up" and resultant concept

    is also applied here with a difference that load in burst will be internal pressure; back up will be

    external pressure.

    OTHER LOADINGS

    Other loadings that may develop in the casing include:

    (1) Bending with tong during make up.

    (2) Pullout off the joint and slip crushing.

    (3) Corrosion and fatigue failure.

    (4) Pipe wears due to running wire line tools and drill string assembly in deviated and dog-

    legged holes.

    (5) Additional loadings arising from treatment operations like acidizing, hydro fracturing,

    cement squeezing etc.

    Additional loadings cannot be determined directly and, it is assumed that they are taken care by

    the Safety Factors.

    Casing design is not an exact technique because of the uncertainties in determining the actual

    loading sand also because of change in casing properties with time resulting from corrosion and

    wear. Design Factor is used to allow for such uncertainties and to ensure that the rated

    performance of the casing is always greater than the expected resultant loading.

    In other words, casing strength is down-rated by a chosen safety factor. Every organization has

    its own policy of safety factors. Most commonly used design factors for casing design are:

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    Collapse 0.85 -1.125

    Burst 1.00 -1.10

    Tension 1.60 -1.80

    Safety factors can be defined as the ratio between rated capacity of casing and the actual load.

    SFcollapse Ratedcollapseresistanceofcasing

    Actualresultantcollapsepressure

    SFburst RatedburstratingofcasingActualresultantburstpressure

    SFtension

    Ratedyieldstrength

    pipebodyorjointwhicheverisminimum

    Actualresultanttensileload

    BIAXIAL EFFECTS

    Burst and collapse resistances of casing are altered when the pipe is under tension or

    compression load. These changes may, but do not necessarily, apply to connectors. Coupling

    manufacturers should be consulted in stringent operating conditions. The qualitative changes in

    pipe resistance are as follows:

    An easy and faster way of finding the quantitative effect of axial tension on collapse resistance is

    by referring to the collapse curve factors.

    To determine the collapse strength under a given tensile load, divide the tensile load by the pipe

    body yield strength, to obtain load factor(X). Read collapse rating factor (V) against load factor

    (X).Multiply rated collapse strength with collapse rating factor (V) to find reduced collapse

    strength under the tensile load.

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    CHAPTER 6: CASING CONSIDERATIONS

    CASING CONSIDERATIONS

    Number of casings is dependent upon the following

    1. Depth of the well

    2. Formations

    DEPTH OF THE WELL

    The casing is mainly dependent upon the depth because if depth increases and number of casing

    strings are increased. If depth is decreased i.e. casing strings are also decreased

    Example

    Certain depth of the well is around 5500m i.e. number of casings 5 casings are installed because

    it will not stable for 4 casings

    Certain depth of the well is around 4000m i.e. number of we need to 4 casings only because

    depth is low and casings are also low

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    Formations

    Formations are key role to play to determine the number of casing string in a bore hole

    formations are weak can not lower the casing strings because cement raising problems casing

    will be collapse and casing shoe is located most probably harder formations

    some formations high pressure and high temperature depth to very critical to control well so

    much of problems arise in this formations easily stuck up pipe drill bit moves low without

    control of formation pressure we can not drill well then casing will be only to prevent the such

    type of casings

    Examples for some formations:

    Shale, coal, silt, basalt, argillaceous, argillite, clay, dust, loam, marl, micrite, micstone, mud,

    mud rock, mudstone, petite, phylite, slate

    This formation are unstable in a well these formation causes in mud loses

    With out casing these type formations handle very difficult

    CASING CONSIDERATIONS

    Conductor casing

    Surface casing

    Intermediate casing

    Production casing

    Conductor casing considerations:

    The conductor casing serves as a support during drilling operations, to flow back returns during

    drilling and cementing of the surface casing, and to prevent collapse of the loose soil near the

    surface. It can normally vary from sizes such as 18" to 30".

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    The first string run or placed in the well is usually the drive pipe, or conductor casing. Depths

    range from 40 to 300 ft. In soft-rock areas such as southern Louisiana or most offshore

    environments, the pipe is hammered into the ground with a large diesel hammer. Hard-rock areas

    require that a large-diameter, shallow hole be drilled before running and cementing the pipe.

    Conductor casing can be as elaborate as heavy-wall steel pipe or as simple as a few old oil drums

    tacked together.

    A primary purpose of this string is to provide a fluid conduit from the bit to the surface. Very

    shallow formations tend to wash out severely, and must be protected with pipe. In addition, most

    shallow formations exhibit some type of lost-circulation problem that must be minimized.

    An additional function of the pipe is to minimize hole-caving problems. Gravel beds and

    unconsolidated rock may continue to fall into the well if not stabilized with casing. Typically, the

    operator is required to drill through these zones by pumping viscous muds at high rates.

    Surface casing considerations

    The purpose of surface casing is to isolate freshwater zones so that they are not contaminated

    during drilling and completion. Surface casing is the most strictly regulated due to these

    environmental concerns, which can include regulation of casing depth and cement quality. A

    typical size of surface casing is 13 inches.

    Drilling conditions will require that an additional string of casing be run between the drive pipe

    and surface casing. Typical depths range from 600 to 1,000 ft. Purposes for the pipe includes

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    solving additional lost-circulation or hole-caving problems and minimizing kick problems from

    shallow gas zones.

    Surface Casing Many purposes exist for running surface casing including:

    Cover freshwater sands.

    Maintain hole integrity by preventing caving.

    Minimize lost circulation into shallow, permeable zones.

    Cover weak incompetent zones to control kick-imposed pressures.

    Provide a means for attaching the blowout preventers.

    Support the weight of all casing strings (except liners) run below the surface pipe.

    Intermediate casing considerations

    Intermediate casing may be necessary on longer drilling intervals where necessary drill

    mud weight to prevent blowouts may cause a hydrostatic pressure that can fracture

    shallower or deeper formations. Casing placement is selected so that the hydrostatic

    pressure of the drilling fluid remains between In order to reduce cost, a liner may be used

    which extends just above the shoe (bottom) of the previous casing interval and hung off

    down hole rather than at the surface. It may typically be 7", although many liners match

    the diameter of the production.

    The primary applications of intermediate casing involve abnormally high formation pressures.

    Because higher mud weights are required to control these pressures, shallower weak formations

    must be protected to prevent lost circulation or stuck pipe. Occasionally, intermediate pipe is

    used to isolate salt zones or zones that cause hole problems, such as heaving and sloughing shale.

    Drilling liners are used for the same purpose as intermediate casing. Instead of running the pipe

    to the surface, an abbreviated string is used from the bottom of the hole to a shallower depth

    inside the intermediate pipe. Usually, the overlap between the two strings is 300 to 500 ft. In this

    case, the intermediate pipe is exposed to the same drilling considerations as the liner

    Liners considerations

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    Drilling (and production) liners are used frequently as a cost-effective method to attain pressure

    or fracture-mud-weight control without the expense of running a string to the surface. When a

    liner is used, the upper exposed casing, usually intermediate pipe, must be evaluated with respect

    to burst and collapse pressures for drilling the open hole below the liner. Remember that a full

    string of casing can be run to the surface instead of a liner, if required (i.e., two intermediate

    strings).

    Production casing

    The production casing is often called the oil string. The pipe may be set at a depth slightly above,

    midway through, or below the pay zone. The pipe has the following purposes:

    Isolate the producing zone from the other formations.

    Provide a work shaft of known diameter to the pay zone.

    Protect the production-tubing equipment.

    Casing policies

    Why four casing are used

    Casing policy is determined Institute of drilling technology ONGC Dehradun in India

    Mainly casing policy dependent upon the off set well data

    In offset well data approximately same borehole properties and many cases casing policy

    is determined we using off set well data

    Four casing policy

    Casing policy dependent upon the depth of the well and formations this two main

    functions to plan four casings in a bore hole

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    Four casings are used

    Conductor, surface, intermediate, production

    Main criteria to use four casings is well will be safely

    Four casing policy fields malleswaram, ravulapaleum Krishna Godavari basin in Andhra

    Pradesh

    Why Three casing policy are used

    This type of casing are used lower depth maximum dependent upon formations

    Three casing are

    Conductor, surface, production

    Three casing policy fields kesanpalliy Krishna Godavari basin in Andhra Pradesh Gulf of

    Cambay basin in Gujarat

    These type formations they did not require the intermediate casing because middle of the

    bore no abnormal formation and formation pressure is low

    Advantages of four casing policy

    Well will be safely to drill to reach depth of the well

    To handle the abnormal formation in the bore hole

    To prevent formation pressure not enter the bore hole

    Disadvantages of four casing policy

    Cost effectiveness high casing cost is 30% of the well effected total coast

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    Two casings policy it is not possible because well will be collapsed it is only applicable

    for Rajasthan fields these areas having no water bed in the bore hole they need not

    installed surface casing two casing means conductor casing and production Example

    Rajasthan area around depth 2200m they installed conductor 700 ft and production

    2200m

    ECONOMICAL REDUCTION

    Casing cost is one of the largest items of the drilling project to represent up to 30% total

    cost of the well

    At present conditions all companies 90 % used four casing policy

    My objective to consider and comparative four casing policy and three casing policy and

    formation correlated I have choose four casing policy to reduce three casing policy by

    using casing setting depth graph

    To reduce at least 5-8% total cost of the well

    To use the linear

    And eliminating one casing by the correlating formations if no water bed bore hole and

    eliminating surface casing this depth controlled by intermediate casing

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    CONCLUSION

    By using casing setting depth graph we know the number casing strings installed and

    exact depth of casing shoe location

    Mud loses and pressure depletion

    Abnormal formations means gas pockets

    Economical reduction means eliminating one of the casing string it possible only for to

    control formation in the bore hole otherwise well will be consider

    My project is applicable for new fields means no off sett well data

    Before starting of drilling to design a casing policy using a offset well data and newer

    fields using seismic survey to know pore pressure data and fracture pressure data to

    prepare a casing policy

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    REFERENCES:

    Fracture pressure and pore pressure data collected from ONGC malleswaram field rig NO

    E-1400-17 well no 102

    Casing design data collected from online journal petro wiki and one petro and rig zone

    Aadnoy, B.S. 2010. Modern Well Design, second edition, Leiden, The Netherlands: CRC

    Burgoyne, A.T. Jr., Chnevert, M.E. and Millheim, K.K. et al. 1986. Applied Drilling

    Engineering, Vol. 2, 330-339. Richardson, Texas: Textbook series, SPE

    Norsok standard D-010 Well integrity in drilling and well operations, third edition. 2004.

    Lysaker, Norway: Norwegian petroleum industry

    OLF117 Recommended Guidelines for Well Integrity, fourth edition. 2011. Stavanger,

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