Problemas y/o trastornos específicos de aprendizaje

The minimum casing shoe setting depth is usually driven by several considerations as for example:

- to isolate overlaying instable formations;

- to isolate overlaying shallow hydrocarbons;

- to isolate overlaying lost circulation zones;

- to isolate overlaying fresh water horizons;

- to prevent failure of formations by induced circulating pressures during drilling operations like circulating, drilling and tripping;

- to prevent failure of formations by induced circulating pressures during well control operations when closing in and circulating out an influx.

The first four considerations depend on local Opco procedures and are location specific. The last two considerations will be discussed in depth in this chapter. These are applicable for all casing strings. Additional requirements for marine conductors are discussed in [7,8].

During the last two events the wellbore below the actual casing shoe under consideration will be subjected to several different types of pressure loads. These pressure loads will have to be compared to the capacity of the wellbore to be able to contain these pressures or, in the event of wellbore failure, not to result in uncontrollable fracture propagation. The comparison of the greatest loading on the wellbore with the wellbore strength will lead to the determination of the minimum casing setting depth.

Below the SIPM criterion for casing shoe setting depth for these considerations is explained. This is followed by a discussion on the wellbore loading resulting from well control, drilling, circulating and tripping operations. The design parameter which finally defines the wellbore strength will be expanded upon.

4.3.1 Design criterion

The primary consideration is to prevent failure of the formation at the casing shoe and the formation in the open hole section below must remain intact under all realistic load conditions.

Additionally, if the wellbore fails, the well design must allow a stable situation to exist for the damaged well. These two requirements can be expressed as a relation between the pressures in the well, the load, and the strength of the wellbore. These are:

- The estimated Formation Breakdown Pressure (FBP) of any formation below the casing shoe should not be exceeded during normal operating conditions, including well control, drilling, circulating and tripping.

- The mud weight gradient, required to balance the anticipated pore pressures in the open hole section, should never be higher than the estimated equivalent mud gradient of the Fracture Closure Pressure (FCP) in any of the formations in the open hole section.

If these requirements are met, the well bore will not fracture, and the well will not experience uncontrolled losses under design conditions. These design conditions relate to the maximum influx that can be closed in and circulated out, and to the maximum circulating rate and trip speed to be experienced. In addition, if the formation accidentally fractures and a loss or kick/loss situation develops, it will be possible to return the damaged well to a stable situation, without significant gains or losses, once the well has been circulated to mud.

This procedure is to be followed for any casing string, usually starting at the total depth (TD) and working upwards.

The following two tables present a few scenarios and most likely consequences of bore hole failure [9]. From these tables above dual requirement has been derived. Additional literature about the consequences of wellbore failures can be found in [10,11,12].

TABLE 1 : FAILURE SCENARIOS WHILE TRIPPING OR CIRCULATING (DRILLING)

TABLE 2 : FAILURE SCENARIOS WHILE CIRCULATING OUT AN INFLUX

4.3.2 Determination of wellbore pressure load

As discussed in the previous paragraph the wellbore will be subjected to several pressure loads during drilling operations. This paragraph will address the determination of these loads by dividing them into two groups:

- Pressure loading during drilling, circulating and tripping operations.

- Pressure loading during well control operations.

4.3.2.1 Pressure loading during drilling, mud circulation and tripping

The determination of the pressure loading on the wellbore when drilling, tripping or circulating can be established by applying physical models. The presently available SIPM supported computer models are HYDRAUL and SWABSURGE, available via OSCP [13]

Swab and surge experiments have been performed in oil based mud to validate these models [14]. It was established that transient pressures induced by pipe accelerations can be much higher than the pressures created by constant tripping speeds. The pressures induced at the bit due to tripping will propagate through the whole well to bottom. Gelling does not seem to have a significant effect on the swab and surge pressures induced. Both swab and surge pressures are induced in either of the pipe movement directions.

SWABSURGE is capable of estimating swab and surge pressures reasonably accurately as long as the tripping speed is constant.

4.3.2.2 Pressure loading during well control

The determination of the pressure loading on the wellbore when circulating out an influx can be divided into two aspects influx volume determination and wellbore pressure calculation. Recent advances in Shell Research Rijswijk on the topic have been documented in [15].

For the determination of the well specific design influx and for the calculation of the wellbore pressure loading, the kick pressure profile, an integrated single bubble model has been developed [16]. The casing designer is responsible for establishing this design influx and the relevant wellbore pressure. The locally applied detection techniques, shut-in procedures and level of training all influence the value of this volume. Therefore a computer program, WELLPLAN/WINDOWS, will be made available to assist in the calculations. The implemented model contains the following features.

1) Influx volume calculation for kicks during drilling, after pump shutdown or for a swab kick, taking into consideration:

- transient production behaviour of the reservoir;

- the rate of penetration into the reservoir;

- the detection of the kick on flow rate out increase or pit volume increase including the hidden volume factor [17];

- the effect of loss of annular friction on the production rate of the reservoir when the pumps are shut down after detection of the kick;

- the reaction time of the drilling crew after detection of the kick;

- the shut-in method [18].

This model makes it possible to calculate the design influx under a given set of circumstances, instead of relying on a default value such as 100 bbls (16m³) or a 12¼" hole.

As illustrated in Figure D2, taking a more realistic locally established estimate of the well influx -e.g. 4 bbls (0.6 m³) assuming fast kick detection and control response or 55 bbls (8.7 M³) assuming slow response has an appreciable effect on the calculated kick pressure profile and hence on the casing setting depth selected.

FIGURE D-2 : EFFECT OF WELL INFLUX ON KICK PRESSURE PROFILE

2) Wellbore pressure, i.e the kick pressure profile, calculation during the killing phase with a kick volume obtained from above calculation. The kick pressure profile is calculated considering:

- a temperature profile in the well during mud circulation;

- the gas compressibility factor : Z-factor;

- the wellbore deviation in the planned trajectory.

The effect of this advanced model on the kick pressure profile is illustrated in Figure D-3 and shows a reduction in the design pressure load compared to the description of the gas behaviour as per PV = Constant.

FIGURE D-3 : ADVANCED WELLBORE PRESSURE MODEL REDUCES DESIGN PRESSURE LOAD

With the increase of data above calculations may have to be repeated during the well drilling phase [19].

4.3.3 Determination of wellbore strength

Formation strength, as discussed in detail in Chapter C, is the other critical design parameter for casing shoe setting depth. With respect to this parameter two significantly different phases can be distinguished:

Well design phase: In this phase the preparation of the best estimate of the lithological model, formation strength profile and pore pressure profile is addressed. This will determine the number and setting depths of casings.

Well drilling phase: In this phase the measuring and reporting of formation strength parameters is addressed. Confirmation and updating of the well design assumptions, if necessary, can change the well design. In addition, the data should be properly documented and stored.

Formation strength

• Prediction

Gathering of data on formation strength is an integral part of casing design. It is important during both the design and the drilling phase. The establishment of a good regional model of formation strength is of great importance for the optimisation of future wells and for optimal field development planning. This data gathering has extensively been addressed in the Chapter C on Design Parameters [9].

In the design phase, a best possible estimate will have to be made of the formation strength.

This may be done using an advanced regional formation strength model, offset well data, or a simple empirical relationship for those wells, where no other data is available.

However, in the absence of a more accurate formation strength model, the leak off pressure (LOP) of offset wells should be used as a conservative approximation for the formation breakdown pressure (FBP). Also the minimum in-situ stress, i.e. the fracture closure pressure (FCP), can be approximated using this LOP value in the equations derived in the Chapter C on Design Parameters.

• Measurement

During the drilling phase, the assumptions of the FBP made during the casing design phase must be checked by carrying out Limit or Leak-off tests. For every well, a Limit or Leak-off test should be carried out at each casing shoe. If drilling through a BOP from the conductor casing will be done, a test below this conductor casing shoe should be scheduled. If drilling will be carried out below a production casing, it should be considered as another intermediate casing and a normal Limit or Leak-off test should be carried out. In addition, a Limit or Leak-off test should be repeated at every formation where the FBP can be expected to be significantly less than the strength measured during the previous test, and where further drilling will be done in that section. Note that during a Leak-off test, the exposed formations have been subjected to higher pressures than the LOP. The highest pressure applied during the test could be used as a less conservative estimate for the FBP, because it has been confirmed that the formation still does not break down under this load. If this FBP estimate is used, also a less conservative value for the minimum in-situ stress (FCP) can be determined. If a Leak-off test is repeated, the last observed result should be used as the maximum pressure that the formation can be subjected to, because this measurement will give the beat indication of the current strength of the open hole [9]. The Chapter C on Design Parameters expands on the relevant aspects of (repeat) testing and reporting.

In general the above methods for establishing the formation strength result in a conservative value. When drilling wells in new areas, or in those cases where additional regional information is valuable, it should always be considered to carry out a more complete formation strength test, including formation breakdown. This way, useful data on formation breakdown, fracture closure and in-situ stress can be obtained. The advantage of a good theoretical/empirical formation strength model, may well offset the risk associated with a small reduction in formation strength caused by a fractured casing shoe. If operational considerations do not allow these tests to be performed during drilling, it should be considered to conduct these tests on abandonment of wells.

4.4 References

[1] SIPM, EPO/51

Making the most of Well Planning EP 92-2500

[2] SIPM, EPD

Technology development programme 1992-1994 EP 92-0350

[3] SIPM, EPO/5

Management, Technology and Human Resources, Programme 1991-1993 EP 91-3000

[4] Worrall, R.N, van Luijk, J.M., Hough, R.B., Rettberg, A. and Makohl, F., KSEPL An evolutionary approach to slimhole drilling, evaluation and completion SPE 24965, KSEPL Publication 1129, 1992

[5] Ross, B., KSEPL

Innovative slimhole completions

SPE 24981, KSEPL Publication 1130, 1992 [6] SIPM, EPO/51

Drilling Spearhead Documentation, Vol. 1, 2 and 3 EP 89-0115

[7] SIPM, EPD/5

Practice for the analysis and design of marine conductors EP 87-0160

[8] SIPM, EPD/51

Conductor setting depth EP 89-1245

[9] Wind, J.A. and Marchina, P., KSEPL Formation strength for casing design EP 92-1454

[10] Kooijman, A.P., KSEPL

A review of the literature on cratering related to subsurface safety valve setting depth EP 90-3071

[11] Walters, J.V., KSEPL

Internal blowouts, cratering, casing setting depths, and the location of subsurface safety valves

SPE 20909

[12] Kooijman, A.P., KSEPL

Simulation of cratering related to internal blowouts - Small- scale tests RKRS.92.DW1

[13] SIPM, EPO/51

OSCP User Guide - version 2.3 EP 91-2156

[14] Surewaard, J.H.G., KSEPL

Preliminary study of swab and surge pressures in oil-based mud EP 91-0253

[15] Hage, J.I., Surewaard, J.H.G. and Vullinghs, P.J.J.

Application of research in kick detection and well control KSEPL Publication 1116, 1992

[16] Surewaard, J.H.G., KSEPL

Improvements to the influx volume calculations and the single bubble kick model EP 92-0984

[17] Surewaard, J.H.G., KSEPL Progress report on Well Control

Part 1: Kick detection and shut-in procedures EP 91-2404

[18] Surewaard, J.H.G., KSEPL

Comparison of well-control shut-in procedures RKRS.92.DW2

[19] SIPM, EPO/51

Pressure control manual for drilling and workover operations EP 89-1500