Drilling programme preparation

Drilling Programmes can be broken down into 11 main sections:

Section 1

Well details

2

Well objectives

3

Casing design

4

Wellhead selection

5

BOP requirements

6

Cementing programme

7

Deviation programme

8

Survey requirements

9

Mud programme

10

Bit and hydraulics programme

11

Evaluation requirements

12

Operational procedure and time depth graph construction

13

Site plan

14

Reporting requirements and contact numbers

All Drilling Programmes will contain the above information in some form. These sections are covered in more detail below. Specialised wells could also contain other relevant data.

SECTION 1: WELL DETAILS

This is a brief summary of the well location, type, depth, operatorship and ownership. A typical layout of this is shown below:

Well name Well type Country Block

Godwana 3 Appraisal Moldavia 20/12

Surface co-ordinates

Subsurface co-ordinates

Target size Target depth TVDSS Target depth AHSS Water depth Operator Partners interest

200 ft radius 10 000 ft 10 000 ft 200 ft

Alpha Oil Co (40%) Beta OU Co (20%) Gamma Oil Co (20%) Delta Oil Co {20%)

Name of rig Type of rig Seabed condition Expected spud date

15M jack-up Sand/silt flat 3rd Quarter 1991

SECTION 2: WELL OBJECTIVES

Well objectives have been discussed earlier in this chapter. A typical format for setting out the objectives would be as follows:

The Godwana 1 well is an appraisal well whose objective it is to establish the presence of the Huey, Louey and Duey sand stones at + 10 000 ft.

All three sand stones will be cored and depending on findings, be production and injectivity tested.

After testing, the well will be either plugged back and abandoned or suspended for later use as an injection well.

SECTION 3: CASING DESIGN

Casing tubulars are put into a well bore for the following reasons:

  1. To isolate troublesome or unstable formations which may include heaving shales, lost circulation zones and flowing halites.
  2. To isolate different pressure or fluid regimes:
  • a) To protect fresh water horizons especially domestic water bearing sandstones in land wells.
  • b) To protect producing formations from mud and water contamination.
  • c) To protect weaker zones from breakdown caused by heavy muds whose hydrostatic is required for pressure control purposes in lower sections.
  1. To control well pressure by containment of downhole pressure.
  2. To provide a stable environment for packers, liner hangers etc.
  3. To support the wellhead and BOP stack.
  4. To confine produced fluid to the wellbore and provides a flow path for it.

A typical offshore well may have a 30 inch conductor, a 20 inch surface casing, 133/s inch and 95/s inch intermediate casing and a 7 inch production liner. Although the above is a common arrangement, there is a multitude of different combinations of casing sizes which the operator may choose to run if he desires and if the casing

The following is a summary of the major functions for each type of casing:

Conductor seals off shallow unconsolidated formations and protects the wellbore from collapsing. It is the first string of casing upon which the BOPs can be mounted, usually being a diverter only, if it is preferred to handle gas at surface as opposed to venting at seabed. It must be able to support the weight of subsequent casing strings, the wellhead and BOPs. With the exception of floating vessels, the conductor may

Surface casing will case off unconsolidated formations, and protect against shallow gas flows. Especially pertinent on land wells, this casing should ensure fresh water sands are not contaminated with drilling fluids or hydrocarbons from other zones. Near surface lost circulation zones can be cased off. Because the main BOP stack normally sits on this casing's wellhead, the installation of the surface casing gives full

Intermediate casing will case off troublesome lost circulation zones, thus protecting them from the high pressures resulting from heavy muds or kicks when drilling deeper zones. They will nearly always be set in a pressure transition zone.

Production casing is the casing inside which the production tubing or testing string is run. It will separate and isolate the productive intervals from each other, and ensure

Liners allow achievement of a production string at low cost because they hang off typically 150 m above the intermediate casing's shoe. They are often used as an additional contingency string, to be run if problems arise. Scab liners are run to protect casing from wear, or to repair damaged or worn casing. They are run on top of an existing liner. The well planner must ensure that the casing is designed accurately and sensibly, not only in the interests of well control, personnel safety, but

In addition to the above, the relevant government department may request seeing the casing design prior to granting approval for drilling the well. The operator may

Casing design incurs risk and the designer must reduce this to an acceptable level. Assumed loadings exerted on the tubulars will not be exact and the properties of the steel are variable, even though the material is within its designed specification. In addition to assuming worst case situations, the designer must incorporate design safety factors dependent on the reliability of his offset data. At the end of this section, we discuss centralisation and casing running principles.

Exactly how much of this should be built into the Drilling Programme will be dependent on how comprehensively this is covered in the Drilling Operations Manual.

Pressure profile chart

A major section of the design work involves construction of the Pressure Profile Chart showing expected pore pressures and fracture gradients. It is the basis of the complete design and time should be taken to ensure that it is drawn correctly. Construction of the Pressure Profile Chart is especially useful for rough line sketching to look at the burst mode situation. Calculations can then be performed to verify the graphical solution and check the collapse and tensile conditions. The following minimum data is required:

  1. The prognosed lithological column, including error bands on the tops of the formations.
  2. Offset wells pore pressure data, including mud logging information, RFT and DST values and the pressures from any influxes. Details of mud weights used may prove useful.
  3. Offset wells fracture gradient data, coming mainly from leak-off tests but also from lost circulation zones.

The pressures obtained from the offset wells must be depth matched to the relevant formation on the prognosed geological column, prior to plotting. In the event that no fracture gradient pressures are available, i.e. in rank wildcat wells, equations such as those used by Eaton can be utilised. In practice, this is rarely necessary.

The overburden stress gradient is a value quoted to indicate the pressure resulting from the compaction of strata above.

The Design Engineer will have to liaise with the Geologist to confirm that the wells he uses as major offsets are the most relevant to the planned well. Because of natural geology including faults, offsets which are closest may have very different lithologies or pressure regimes from the well being designed. Implications of using inaccurate offset well data may be that the casing is under designed to an unsafe level or over designed to the detriment of economy. A different offset may have to be used for the lower part of the well than what was used for the upper section.

Initial design approach

By the time the pore pressure chart has been constructed, the Drilling Engineer should have a reasonable idea of what casing sizes he will use and their setting depths. Choice of the casing OD will depend on availability of standard diameters, programmed hole sizes and likely rig choice. The final hole size for logging and the likely production string must both be given consideration. The Planner will have to liaise with Petroleum and Production Engineers at this early stage. For a normal offshore exploration well, it is recommended that a 8V2 inch hole be the smallest diameter planned for because of drilling and evaluation difficulties encountered with a 6 inch hole. A 6 inch hole should only be planned for as a contingency.

The setting depth will depend on competent formations with high fracture gradients as indicated in offsets, lengths of open hole sections and requirements for cementing programmes.

A sense of reality must prevail during casing design. The logistic implications of mixed grade strings or grades can outweigh any potential economic advantages they might give. Remember that someone has to run the casing into the ground at the end of the day and it is in everyone's interest to try to keep that part of the operation as simple and trouble-free as possible.

Reservoir fluid gradient

The fluid within the reservoir and therefore its gradient has a direct bearing on the burst mode calculations, and it is very important to research the information carefully. A gas gradient is always used in the reservoir, its value being the minimum possible, unless good information from the production testing of offset wells indicates otherwise. Minimum values are unlikely to be less that 0.14 p.s.i./ft (0.32SG). The reservoir gas gradient should also be used in larger diameter hole sections above the reservoir. This makes the worst case assumption that gas enters the higher section by migration or an inadequate seal. (It is only the fluid gradient which is assumed to be the same and not reservoir pressure.)

Casing shoe setting depths

The general criteria for the selection of casing shoe setting depths must be that the preceding hole section can be drilled successfully and safely. The casing shoe must be set in competent formations that will be able to withstand the forces imposed upon it should a pressure kick occur.

The shoe depth selected for the conductor pipe should be such as to provide a shoe strength strong enough to withstand fracturing during drilling the next hole interval which is assumed to have no hydrocarbon intervals. 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 is treated as for the conductor pipe if no hydrocarbons are expected in the next hole interval or alternatively as for the intermediate and production casing, in the event that hydrocarbons can be expected.

The shoe depth selected for intermediate and production casing should be such as to provide a shoe strength strong enough to withstand fracture during drilling the next hole section, according to the criteria established for the conductor pipe and also strong enough to take a gas kick of defined volume. The mechanisms for selecting a shoe depth are as follows:

  1. Clearly define well objectives.
  2. List actual problems encountered in nearby wells.
  3. List potential problems encountered in nearby wells.
  4. Estimate pore and fracture pressure profiles for well.
  5. Overlay pore and fracture pressure profiles with expected well lithology targets and objectives.
  6. Make a basic casing design (try four strings).
  7. Study production casing, shoe depth requirements to satisfy designed kick tolerance.
  8. Select suitable formation and depth to meet this requirement as an absolute minimum.
  9. Recalculate kick tolerance for selected shoe depth.
  10. Study intermediate casing shoe depth requirements to satisfy designed kick tolerance.
  11. Select suitable formation and depth to meet this requirement as an absolute minimum.
  12. Recalculate kick tolerance for selected shoe depth.
  13. Study surface casing shoe depth requirements to satisfy next hole section requirements.
  14. Select suitable formation and depth to meet this requirement as an absolute minimum.
  15. Study conductor pipe shoe depth requirements to satisfy next hole section requirements.
  16. Select suitable formation and depth to meet this requirement as an absolute minimum.

Kick tolerance (KT) is a determination of the size of kick that can be safely shut-in and circulated out of the well. Kick tolerance should be calculated both:

  1. At the programming stage for the formation at the chosen casing shoe depth for all casing strings below the conductor.
  2. During drilling once a formation leak-off test has been performed use the formation strength figures to recalculate the kick tolerance. Periodically during drilling, recalculate kick tolerance as mud weight changes or potentially weaker formations are penetrated.

Since in most cases, the weakest point in the hole is immediately below the casing shoe, the kick tolerance can be calculated by determining the pressure at casing shoe when the top of the gas bubble is circulated to the casing shoe. The kick tolerance is calculated from the following equation:

KT= SDxSFSxAnn xi(SDxSFS)-FD + MG (TVD-SD)] PFx(MG-GG)

where

KT = volume of influx in barrels that can be tolerated Ann = annular capacity below shoe, hole/DP (bbl/m) SD = depth to casing shoe (m) TVD = depth of section (m)

SFS = formation breakdown gradient {p.s.i./m)

Design criteria

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

1. Burst

  1. Collapse
  2. Tension
  3. Compressional effects

Burst is pipe failure which occurs when the pressure inside the pipe is greater than the internal yield value of the pipe plus the pressure outside the pipe. Burst mode calculations must be made to ascertain exactly what volumes of gas kicks can be taken and at what pressures.

Both the strength of the formation at the shoe, and the burst strength of the casing must be considered. The ideal situation is for both formation and casing to be able to withstand the pressures resulting from a full gas column to surface and the additional pressures resulting from circulating the gas out. However, for deeper wells of a higher pressure, it must be accepted that both formation and casing may have to be designed on a limited kick basis.

It is recommended that the pressure profile chart method is used for the complete burst scenario.

  1. To roughly ascertain kick volumes and casing burst values.
  2. As a final graphical representation for presentation. Included in the graph will be lines representing pore pressure, fracture gradient, gas gradient, mud gradient, net burst, casing burst and lengths of allowable kicks.

The graphical presentation will show the situations for burst on the formation and burst on the casing.

The Drilling Engineer should ensure that the formation at the shoe is always weaker than the casing. This criteria is in the interests of the safety of both personnel and the rig. If pressures resulting from a gas kick were to rise to an unanticipated level when shut-in, an underground blowout is preferred to the casing failing.

In the design stage every factor involved in the burst on the formation calculations is an estimate based on offset data. As the well is being drilled, these figures should continually be recalculated as more accurate information evolves. At minimum, this should be performed after every leak-off test is conducted.

However, it is good practice to re-evaluate the kick tolerance at more regular intervals using the mud logger's estimates of pore pressure, especially if the pore pressure profile is increasing. Although the formation at the shoe normally has the lowest iracture gradient in the hole section, it should be borne in mind that weaker formations may exist below the shoe. If the well to be drilled is designed with low limited kick volumes {below 100 Bbls) the operator must ensure that the rig, the rig equipment and the personnel he uses are adequate for fast kick detection and briefed fully on the situation and its implications.

When a formation 'kicks', its flow regime is what is termed 'transient'. It does not immediately conform to the standard steady state flow equations used in production technology and is more analogous to production test flow rather than production well flow. The actual inflow performance will depend on:

  1. Drawdown (the difference between mud, hydrostatic pressure and formation pressure)
  2. Formation porosity
  3. Formation permeability
  4. Wellbore damage (usually due to drilled solids and filter cake blocking well bore pores)

Formation porosity and permeability can be considered to be constant for a given formation in a given well. Wellbore damage and drawdown will vary, however, during the flowing process.

Solids which have been blocking wellbore pores can be pushed back into the wellbore by the flowing influx, hence reducing damage to the wellbore. Furthermore, as gas is produced into the wellbore to take the place of mud in the annulus, the drawdown on the well increases. The significance of these two phenomena, in practice, is that most wells will kick slowly initially, and with increased intensity until they are closed in. Consequently, early kick detection is paramount for safe drilling operations.

Kick detection is a function of the personnel involved, mainly the Drilling Supervisor who lays down the ground rules and the Driller as the first line of detection. It is also dependent on the quality of the kick detection equipment installed at surface. Mud loggers can also play a vital part in kick detection by setting up their equipment properly and having an intimate knowledge of it. Their instrumentation will quite often pick up tank gains before the Driller's instrumentation does.

For a low kick tolerance well, it stands to reason that the operator should closely consider the above. Nothing can be done about the formation or the fluid characteristics, but the hole diameter and annulus volume are dependent on the casing design. The operator should insist that the rig contractor supplies experienced drillers, with additional training if considered it necessary. Kick detection equipment should be of a high standard and an upmarket mud logging package be procured. Utilising a small active system will assist in kick detection.

If the Well Designer has any comments to be made on any aspects of a small kick tolerance well, including considerations of the above, he must detail it in the casing design. It should be borne in mind that the research and work involved in the casing design implies that that particular Planner is the most knowledgeable drilling person associated with the pressure and strength regime in the well.

The Well Designer should ensure that the casing is stronger than the formation in the burst mode. However, it is accepted that there is the odd occasion where the formation gradient data simply does not allow this. A safety factor of between 10 and 30 per cent is usually applied to the internal yield values of the casing.

The liner should be considered first, then the production, intermediate and surface strings, taking the net burst into consideration in all cases. The net burst is the difference between the pressures inside and outside the casing. If it is greater than the casing's rated burst pressure, less design factor, the pipe is in danger of failing.

The worst condition for the liner or production casing is complete evacuation of the test string or completion to reservoir fluid with a tubing leak occurring at the surface. A combined pressure of the annulus hydrostatic plus the surface pressure is exerted above the packer. The worst situation assumes that only pore pressure is behind the liner. If applicable, other factors such as fracturing and acidising must be considered.

In the interest of economy, the liner is often tied back to surface to allow a lower grade production casing to be used. Assuming it is uncemented, the tied back can be retrieved prior to abandonment. For the intermediate strings of casing, the worst condition is assumed to be complete evacuation to the formation fluid. When circulating out a gas kick, the pressures exerted on the upper section of the casing will be greater than the pressures under a static condition. Pressure testing of casing should also be considered.

Collapse will occur when the external force on the pipe is greater than the combination of the internal force plus the collapse rating. It occurs as a result of either or a combination of:

  1. Reduction in hydrostatic head exerted by the fluid inside the pipe.
  2. Increase in hydrostatic head exerted by the fluid outside the pipe.
  3. Mechanical forces created by plastic formations, squeezing salts etc.

The above three factors can result from the following situations:

  1. Inadequate fill up of casing when running
  2. Lost circulation
  3. Cementing
  4. Casing wear (see page 120)
  5. Air or foam drilling. The casing has to be designed for complete evacuation plus an allowance for wear due to loss of lubricity
  6. Halite sections
  7. High drawdowns for testing purposes. It is generally accepted that a rank exploration well will not be subjected to high drawdowns but this should be considered for appraisals.
  8. Acidising of fracturing a horizon could result in an increase in external loading to a depth above the packer if a path of communication exists.
  9. Similarly squeeze cementing could increase external loadings above or below packers.
  10. Corrosion will eventually decrease the collapse strength of the pipe.

For most wells, only the first three situations are usually considered. For the first two, a good indication of resistance to collapse is the percentage of the casing which could collapse, either due to lost circulation or not filling the pipe when running. It should be mentioned that the latter is strictly an operational consideration and not a design one. As such, It should not be a design criteria. The result of the two situations is simply stated as a percentage and no design factor needs to be incorporated. The operator may wish to stipulate a value of say 40 or 50 per cent, being the minimum proportion of casing to be full at all times.

A second method of considering the lost circulation situation is to assume the following worst case. When drilling the next hole section with the maximum allowable mudweight, total losses are experienced. This would result in the mud level inside the casing dropping to an equilibrium level where the mud hydrostatic equals the pore pressure. The operator may wish to stipulate a design factor of between 1.0 to 1.15.

In the third situation, the various cementing possibilities should be considered, to ensure that the heavy cement outside coupled with spacers or light weight mud inside does not induce collapse. Again, a design factor of between 1.0 and 1.15 is usually imposed. Large diameter casings generally have a low collapse resistance. This disadvantage is made worse by the fact that they are often cemented by inner string techniques. Annulus pressures and the possibility of packing off have to be looked at.

For the collapse design of casing strings which are set deeper (say below 12 000 ft), in high mud weights (say above 14 ppg) or have high rates of bending (say above 10 degrees/100 ft), it is recommended that biaxial forces be taken into account (see page 120).

Tensile failure will occur if the pull exerted on the pipe is too great for the tensile strength of the pipe or coupling. With the 'off the shelf string of casing, the coupling is stronger than the pipe (although a check should always be made). That criteria should be specified when ordering from the suppliers. For situations where the coupling has to be special clearance, for example of a smaller diameter than the normal, the coupling will be weaker. The number of parameters which can affect tension means that the estimates for the tensile forces are more uncertain than the estimates for the burst and collapse. The safety factors imposed are therefore much larger, being in the range 1.30 to 1.80. Tensile loads on the casing should be calculated at the following stages:

  1. When running the pipe
  2. When cementing
  3. When pressure testing (drilling phase)

Four situations should be considered and a safety factor evaluated for each one.

Situation 1. Common force plus a shock loading when running

Situation 2. Common force plus an overpull when running

Situation 3, Common force plus a weight of cement force when cementing

Situation 4. Common force plus a pressure test in the drilling phase

The highlighted terms are explained in more detail below.

Common force is a combination of the weight of the casing string less the buoyancy force in the minimum mudweight envisaged plus a bending force.

where

W = casing weight in lb/ft L = casing length in ft

(ii) Buoyancy force (BF) is an upward force acting on the bottom of the casing string. True vertical depths must be used in a directional well. Any composite strings with different ID's must be considered separately.

BF=MWxCSAxL

where

MW=mudweight in p.s.i./ft CSA=cross sectional area in sq ins L=casing length in ft

(iii) Bending force (BeF) is a force acting in tension on the outside of the pipe and in compression on the inside. It will be caused by any deviations in the well, resulting from side-tracks, build-ups and drop-offs or from sagging of casing caused by lack of centralisation or washouts. A radius of curvature of 1 or 2 degress/100 ft is normally used for vertical holes and 5 degrees/100 ft for build up or drop offsections. {It should be noted that a survey may not indicate the real rate of curvature in a dogleg if the stations are not close enough together.) Bending calculations must be re-done if a well has to be side-tracked round a fish.

where

63 = a constant incorporating CSA, W and Youngs Modulus for steel RC = radius of curvature in deg/100 ft D=outside diameter of pipe in ins W = casing weight in lb/ft

Shock loading, when running, is exerted on the pipe because of:

1. Sudden deceleration forces, for example if the spider accidentally closes, or the slips are 'kicked-in' on moving pipe, or the pipe hits a bridge.

2, Sudden acceleration forces, such as picking the pipe out of the slips, or if the casing momentarily hangs up on a ledge then slips off it.

Any of the above will cause a stress wave to be created, which travels through the casing at the speed of sound.

Shock loading = 150 x V x CSA

where

150 = the assumed speed of sound in steel in lb sec/in V = peak velocity when running in in/sec CSA = cross sectional area in sq ins

Overpull contingency of 100 000 lbs is normally incorporated. This is not exactly a design factor but a function of the hole conditions.

Cement force (CF), a worst case situation is assumed as follows: the mudweight in the annulus is the lowest envisaged for the section; the inside of the casing is full of cement slurry, with mud above; the shoe instantaneously plugs off just as the cement reaches it and the pressure rises to a value of say 1000 p.s.i. before the pumps are shut down. It is appreciated that the cement will be 'running away' at this point with no positive displacement pressure being exerted.

where

CW = cement weight in p.s.i./ft MW = mud weight in p.s.i./ft L = length over which CW & MW act in ft A=internal area of the casing in sq ins

Pressure testing will 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:

  1. The rated burst strength of the casing
  2. The well head pressure rating
  3. The BOP stack pressure rating
  4. The maximum anticipated surface pressure

Compressional effects occur in casing due to temperature effects in landed casing and because of the weight of other inner casing strings which must be supported by the outer strings. In most cases the outermost casing will carry some or all of the following compressive loads:

the weight of the intermediate casing strings the weight of the well head any completion tubing tension

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

  1. Land wells and subsea wellheads
  2. Platform wells with surface wellheads
  3. Mudline suspension wells

In land wells, provided the outer casing is cemented all the way to surface it will be able to support all the expected compressional loads. If, however, It is not cemented to surface then there is a danger of buckling due to the compressive loads.

With platform wells with surface wellheads, there is a freestanding part of the casing equivalent to the water depth plus air gap plug height to the wellhead deck. Buckling can occur on this freestanding section. To prevent buckling, the outermost casing must be well centralised within the diver conductor and designed to be strong enough to withstand the likely buckling forces.

With mudline suspension wells, used mostly on jack-up wells, the weight of the casing is hung off at the seabed. The tieback strings which link the seabed wellhead with the surface equipment on the jack are however, subject to buckling. Except in areas of high seas or current a 20 inch surface casing string of 133 lb/ft will be sufficient to support surface equipment in water depths up to 90 m.

During drilling operations, temperature effects are so slight that they can be ignored. During the production phase, however, the compressive loads on the production string must be considered, especially if the well is to be used as an injector. A design factor of 1.0 should be applied in these cases.

Was this article helpful?

0 0
Project Management Made Easy

Project Management Made Easy

What you need to know about… Project Management Made Easy! Project management consists of more than just a large building project and can encompass small projects as well. No matter what the size of your project, you need to have some sort of project management. How you manage your project has everything to do with its outcome.

Get My Free Ebook


Responses

  • Ines
    What is Absolute Safety Factor in Casing Design?
    8 years ago
  • Awet
    How much does 13m surface casing weight?
    8 years ago
  • corey
    What is casing preparation in oil and gas drilling operation?
    1 year ago
  • LUKAS
    Which casing string seals off potentially troublesome formations.?
    3 months ago
  • Hilda
    Why is the casing shoe the weakest point in drilling?
    3 months ago

Post a comment