Casing Design parameters

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Early collection of all the relevant data is essential and it should be done by a multidisciplinary team. Considerable effort is required from the Petroleum Engineering and Operations departments when planning, designing and drilling/completing a well. Because of the high costs, the data set used for casing design must be as complete as possible right from the start. Some of these data are laid down in the development plan, well proposal or well objectives.

However, casing design demands more detailed information on all strata to be penetrated.

The parameters involved will be called the design parameters. These are:

  • lithological column,
  • formation-strength,
  • pore-pressure
  • temperature profiles,
  • hydrocarbon composition
  • H2S/CO2 concentrations.

1 Lithological column

The lithological column is the description of the sequence of formations that are prognosed to be present in the well to be drilled. Every formation should be described in term of strength, drilling problems, reservoir potentials, etc. This information will assist in selecting the depth of the various casing shoes, as the type of formation and its depth will give a good indication of formation strength.

The presence of an aerobic environments can be an indicative for H2S which may be formed by bacterial action.

In combination with offset well pore pressure profiles potential over/under pressure zones may be predicted.

2 Formation-strength profile

2.1 Introduction

Formation strength refers to the ability of rock to withstand a certain load without failure. Different measures of formation strength are used in the different disciplines in the industry:

  • Geology, e.g. modelling of geological structures, trapping mechanisms of hydrocarbon accumulations and mechanisms of overpressures.
  • Drilling Operations, e.g. casing setting depth, maximum safe drilling depth and losses caused by circulating pressures, surge pressures, and cementing operations.
  • Production Operations, e.g. well killing, sand control operations and well stimulation.

The main importance for casing design is the relation between wellbore pressures and the ability of the borehole wall to contain wellbore fluids, both for an intact and a fractured borehole.

2.2 Borehole failure mechanism

The mechanism of borehole failure can be shown in a plot of the downhole pressure, of a closed-in well, versus volume pumped. Initially, the pressure - time relationship is linear. The Leak-Off Pressure (LOP) is the pressure at which the curve deviates from the initial linear build-up. Fluid is going into the formation by filtration or small cracks.

At the Formation Breakdown Pressure (FBP) the borehole fails and a major fracture is initiated. The stress concentrations around an intact borehole provide the strength of a borehole. Once formation breakdown has occurred, these stress concentrations disappear, and the strength of the borehole is reduced to the minimum in-situ stress of the formation.

If pumping is continued, the fracture propagates in a controlled manner, and stabilises at the Fracture Propagation Pressure (FPP). Due to the frictional pressure losses in the fracture, the FPP will increase if the flowrate increases.

When pumping is stopped, flow into the well and into the fracture stops almost immediately; frictional pressure losses disappear, and the pressure drops to a value called the Instantaneous Shut-In Pressure (ISIP). The fracture is open, but does not propagate any more.

The fluid in the fracture then leaks away, through the faces of the fracture into the formation, and the pressure decreases. The pressure at which the fracture closes is the Fracture Closure Pressure (FCP). It can be shown that this pressure is equal to the minimum in-situ stress.

After the fracture has closed the fluid leaks away very slowly, through the mud cake into the formation. The pressure will, given enough time, reduce to the hydrostatic pressure of the mud column. There is no clear transition between these last two situations on the pressure decay curve. Techniques have been developed to derive the FCP, by determining the intersection between the two "trend" lines in the pressure - time plot.

If the fractured borehole is pressured up again, the fracture opens up at the Fracture Reopening Pressure (FRP), which in most cases is equal to the FCP. The fracture continues to propagate at the FPP. The original FBP will not be reached anymore; the strength of the borehole is reduced compared to the original unfractured situation. In some situations the strength of the borehole may be restored. This process is called "clay-healing". However, the mechanism is not understood, and should not be relied upon.

further reading: Basics of Rock Mechanics

2.3 Formation-strength gradient and equivalent mud weight

Formation strength is often expressed as a gradient by dividing the pressure by the true vertical depth relative to a reference level.

In geophysics and rock mechanics, the Formation Breakdown Gradient (FBG) is calculated by dividing the FBP by the true vertical thickness of the overburden. This way formation strength and overburden gradient can be compared. The conversion is different for land and offshore wells

For Drilling Engineering, the Formation Breakdown Pressure is expressed as an equivalent mud gradient. This is the mud gradient of a mud that will give a hydrostatic pressure equal to the Formation Breakdown Pressure at the formation of interest.

2.4 Measuring the formation strength

Formation strength measurements are performed to determine the strength of the wellbore.Different methods exist for determining the strength of a formation:

  • Limit Test or Leak-Off Test - The test is stopped as soon as a predetermined pressure is reached or when leak-off is observed. These tests confirm that the wellbore can withstand the test pressure without breakdown of the formation.
  • Formation Breakdown Test - The well is pressured up until formation breakdown is observed. The test is sometimes continued with a series of fracture opening and closing cycles (microfrac, minifrac test).
  • Measurements on core material will give additional information on rock properties and the orientation of the in-situ stress.
  • Wireline testing - tools are available to measure rock property and formation strength.
  • Analysis of "loss events" - The strength of the open hole can be inferred from a careful analysis of any operational event that causes losses. If losses occur, they should be treated as an opportunity to derive valuable information.

Choosing the right method

The process of deciding which formation strength testing method to choose is characterised by two, usually conflicting considerations:

  • the required accuracy and significance of the results;
  • the requirement to avoid the risk of reduced formation strength, caused by formation breakdown.

In the design stage a trade-off has to be made between the risk of formation strength reduction and the need for realistic formation strength data. These two aspects are discussed below.

a. Accuracy of formation strength testing method

A Limit test confirms that the Formation Breakdown Pressure of the formation below the casing shoe is higher than the limit pressure (LP), but gives little information about the formation itself.

A Leak-off test is an indication of the strength of the borehole and the mudcake. It is an indication of impending formation breakdown, and can be used to estimate the FBP or minimum in-situ stress. However, the LOT has some drawbacks:

  • Breakdown can occur without indications of Leak-off.
  • Leak-off is dependent on parameters that are not related to formation strength (e.g. mud type, length of the open hole section, whether any natural or drilling induced fractures are exposed, borehole condition).
  • Leak-off testing can be difficult to interpret, especially in unconsolidated formations.
  • Leak-off pressures tend to increase with time, especially in sandstone.
  • Leak-off pressures do not correlate closely with the more significant formation strength parameters (for example FBP and FCP or minimum in-situ stress).

During a Formation Breakdown test, the FBP is determined, and the FCP can be estimated. The FCP is equal to the minimum in-situ stress, which is to be preferred as a measure of formation strength. Its value is not dependent on the mud or the borehole orientation or geometry, and can be correlated regionally from well to well. Knowledge of the minimum in-situ stress also offers the possibility to predict FBP for nearby wells at different deviations.

A micro-frac or mini-frac test allows the minimum in-situ stress to be derived with a higher degree of accuracy. Data from these tests can be used to derive regional models of in-situ stress and formation strength. Additional information about fracture propagation is obtained from these tests. This can be used to design well stimulation treatments.

b. Operational considerations

The main consideration is the risk that a reduction in formation strength will occur and that it may jeopardises the success of the well.

The magnitude of the reduction in strength after formation breakdown is unknown, and it is not certain that "clay healing" will restore the strength of the wellbore.

For an optimum well design, the predictions of the formation strength at the scheduled casing shoes must be as accurate as possible. The accuracy of the prediction depends on the validity of the formation strength model and the accuracy, significance and amount of available formation strength data.

If no data are available, assumptions have to be made about the state of stress and only a rough estimate can be made of formation strength. This will usually result in a sub-optimal well design, (either conservative or over-optimistic).

If data from one or more offset wells are available, the basic assumptions on the state of stress can be confirmed, and the accuracy of the prediction increases. If enough high quality data (e.g. micro frac, mini frac or formation breakdown data) are available, a regional strength model can be derived, which will allow a more optimal well design. For some areas in the world formation strength data have been used to determine the relationship between minimum horizontal stress, depth and pore pressure.

In areas where formation strength determines well design, it is recommended to develop correlations. To enable this, it is recommended that formation breakdown tests or microfrac tests are carried out, to determine FBP and FCP, (and the state of stress). If operational considerations do not allow these tests to be performed during drilling, it should be considered to do these tests on abandonment of wells, or in existing wells.

In view of the importance of stress and strength data, not only for subsequent wells, but also for the production phase (e.g. sand failure, compaction, stimulation, etc.) no opportunities should be missed to perform these tests which are relatively cheap in the drilling phase.

2 Pore-pressure profile

The pore pressure profile is an important design parameter for casing design, in terms of both setting depth selection, and required casing capacity for burst as well as collapse loading.

The pore pressure is the pressure of the fluid in the pore spaces of the formation. Pore pressures are often expressed as gradients relative to a reference level. In geophysics and rock mechanics, this is the "Free Water Level" FWL, (i.e. seawater level offshore or ground water level on land).

Classification of equivalent mud gradients:

  • sub-normal pressures< 0.433 psi/ft(< 9.8 kPa/m) depleted horizons, areas with low water table
  • hydrostatic0.433-0.465 psi/ft(9.8-10.5 kPa/m) higher values possible normal depositional environments
  • abnormal pressures> 0.465 psi/ft(> 10.5 kPa/m) hydrocarbon columns, tectonic activity, under compaction, salt domes, uplifting of sediments

Pressure anomalies can be caused by a number of reasons:

  • Hydrocarbon columns. The magnitude of the over-pressure is determined by the length of the column and the difference in density between formation water and hydrocarbons.
  • Compaction effect- formation fluids can not be expelled at a rate in balance with normal compaction of sediments (usually associated with rapid sedimentation rates). As a result pore pressures may be very high, potentially up to lithostatic gradients.
  • Aquathermal pressuring - Over-pressures may be caused when the temperature of a sealed body of water filled sediments is increased (thermal expansion of water is higher than that of rock).
  • Clay diagenesis - the release of interlayer water from certain clays due to a combination of temperature, ionic activity and, to a lesser extent, pressure. This process results in a net increase in volume or, if the expansion is restricted, in an increase in pore pressure. Other types of phase change are also associated with over-pressures (e.g. Gypsum to Anhydrite, ice to water, Serpentine dehydration).
  • Mechanical uplift - Mechanical uplift (tectonic activity, diapirism, faulting/erosion) of isolated reservoir sections without pressure release may result in over-pressures.
  • Charging - Pressures may be transmitted through permeable layers. Formations at a considerable distance from the origin of the over-pressures may be charged. This mechanism may also be man-induced (e.g. internal blowouts, loss of formation fluids, bullheading).
  • Pressure depletion due to formation fluid production - The production of hydrocarbons normally leads to a reduction in the pore pressure below its original value.

Information on pore pressures may be derived from offset wells and from regional geological models.

During the drilling of a well, pore pressures can be inferred from an analysis of the drilling operation during a reservoir fluid influx (e.g. drilling kick or swabbed kick).

In reservoirs of sufficient porosity and permeability, pore pressures can be measured with wireline tools after the well has been drilled. Evaluation of petrophysical (wireline and MWD) data allows the determination of the behaviour of pore pressures in shales.

While drilling an exploration well there is virtually no pore pressure information available. The only indication for pressure anomalies then consists of velocity anomalies on seismic profiles.

4 Temperature profile

Temperature changes from the static geothermal gradient will induce thermal loads on casing strings.

The forces/displacements caused by these changes in temperature can be of considerable importance for:

  • Laterally unsupported sections of casing which may buckle due to the forces resulting from thermal expansion/contraction of the strings.
  • In sealed annuli, the pressure changes caused by thermal expansion/contraction of the fluids between the casings can lead to collapse/burst of strings.
  • Well growth due to thermal expansion must be taken into account in e.g. platform and facilities design.
  • Reduction of yield strength hence reduction of pipe load bearing capacity at elevated temperature has to be taken into account.
  • High pressure/high temperature wells in which near-surface temperatures, initially as low as 60°F (15°C) or less may eventually approach temperatures over 350°F (177°C) after prolonged periods of production.
  • Steam soak operations, in which the wells are cycled over a large temperature range.
  • Injection wells, where during prolonged injection the temperature at bottom will approach the temperature of the liquids at surface.
  • Temperature predictions are also important for sour service casing design, as the grade selection is a function of the temperature.

5 Hydrocarbon properties

The exact hydrocarbons properties are dependent on the type of buried organic matter, time of burial and pressure and temperature after this burial (metagenesis). Hydrocarbons encountered may consist of fluid or gas only or a mixture. Under reservoir conditions the hydrocarbons will have other properties than under surface conditions.

The casing designer uses the hydrocarbon properties to calculate the burst design loads (complete displacement of the casing to gas or influx circulation during well control).

Important design parameter:

  • average density of the hydrocarbons when completely filling the wellbore.
  • compressibility factor (Z-factor), a term by which the pressure must be corrected to account for the departure from the ideal gas equation.

6 H2S, CO2 and non-hydrocarbon formation fluid composition

H2S and CO2 are gases which have a strong corrosive effect on tubulars. Forecasting their presence and concentration is essential for a choice of a proper casing grade and wall thickness and for operational safety purposes

The presence of H2S is of particular concern because of the rapid occurrence and potentially disastrous consequences of sulphide stress corrosion cracking in casing. The NACE definition for these "sour" conditions is an H2S partial pressure over 0.05 psia (0.34 kPa). For a well with a bottomhole pressure of 10,000 psi (68,950 kPa), this represents an H2S concentration of 5 ppm.

CO2 is a potential threat if it is dissolved in water.

Combined information of H2S and CO2 concentration, bottom hole pressure and temperature will provide all information necessary for future sour service and corrosion design. These data usually becomes available after analysis for samples from production tests of offset wells.

Casing can also be subjected to corrosive fluids found in water rich formations and aquifers as well as in the reservoir itself.

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