GB2517502A

GB2517502A - Method of calculating depth of well bore

Info

Publication number: GB2517502A
Application number: GB201315137A
Authority: GB
Inventors: Henrik Manum
Original assignee: Statoil Petroleum ASA
Current assignee: Equinor Energy AS
Priority date: 2013-08-23
Filing date: 2013-08-23
Publication date: 2015-02-25
Anticipated expiration: 2033-08-23
Also published as: GB201315137D0; WO2015024814A2; WO2015024814A3; GB2517502B

Abstract

A method of calculating vertical depth in a well bore containing a well fluid comprises the steps of measuring the pressure of said well fluid at a first location P1 to produce a first pressure value, measuring the pressure of said well fluid at a second location P2 to produce a second pressure value, determining the difference in height between said first and second locations, calculating a fluid density value for said well fluid using said first and second pressure values and said difference in height, measuring the pressure of said well fluid at a third location Pbit to produce a third pressure value, determining a reference pressure Pstp, being the pressure of said well fluid at a reference location, determining the height of said reference location and calculating the vertical depth of said third location using said fluid density value, said third pressure value and said reference pressure.

Description

Method of calculating depth of well bore

FIELD OF THE INVENTION

The invention relates to a method of finding the total vertical depth of the well bore of a drilled well, and is particularly applicable in directional drilling. The method is suitable for both offshore and onshore use.

BACKGROUND OF THE INVENTION

It is known to calculate the vertical depth based on the measured inclination and depth (drilled length). The inclination may be measured using magnetometers, accelerometers or gyros.

Common methods for vertical depth calculation based on inclination and measured depth are the tangential method, balanced tangential method, average angle method, radius of curvature method, and minimum curvature method. The latter method is most commonly used, and is based on the following basic formula: TVD2 = (cos lx CL)+ TVD1, where: TVD2 = new total vertical depth; I = inclination / deviation angle; CL = course length; TVD1 = last total vertical depth.

For more details see: S.J. Sawaryn and J.L. Thorogood, A Compendium of Directional Calculations Based on the Minimum Curvature Method, in SPE Annual Technical Conference and Exhibition (2003) and H.S. Williamson, Accuracy Prediction for Directional Measurement While Drilling, SPE Drilling & Completion, 15(4):221-233 (2000).

However this method can be inaccurate for large hole depths and for directional drilling.

SUMMARY OF THE INVENTION

The invention provides a method as set out in the accompanying claims.

Embodiments of the invention will now be described, by way of example only, with reference to the accompanying figures.

BRIEF DESCRIPTION OF THE FIGURES

Figure 1 is a schematic diagram showing the use of the invention in a directed well containing a wired drill pipe; and Figure 2 is a schematic diagram of an individual drill pipe segment of the drill pipe shown in Figure 1.

DESCRIPTION OF PREFERRED EMBODIMENTS

Figure 1 shows a directed well bore 2 which has been formed by directional drilling using a drill bit 4 attached to the end of a drill pipe 6. The drill pipe 6 (also sometimes referred to as a drill string) is driven by a top drive 8.

During drilling fluid is pumped down through the drill pipe 6 in the direction of arrow 10, and the fluid returns up the well bore 2 in the direction of arrows 12. This fluid is sometimes referred to as mud, and may be a mixture of oil and water. Various substances or chemicals may be added to the fluid, for example to change the density and/or viscosity of the fluid, in order to keep the pressure in the well bore 2 within an acceptable range during drilling.

As shown in Figure 1, the well fluid is pumped from the top of the well bore 2 to mud pits (not shown) in the direction of arrow 14, and is pumped from the mud pits to the top of the drill pipe 6 in the direction of arrow 16. The fluid from the mud pits passes through a stand pipe manifold 18 before reaching the drill pipe 6.

Figure 2 is a schematic diagram of an individual drill pipe segment 20. The drill pipe 6 is formed from a plurality of individual pipe segments 20 which are connected together to form the drill pipe 6. In this embodiment each drill pipe segment 20 is 9 to 10 metres in length.

Each pipe segment 20 contains a cable 22, which may be a coaxial cable or any other suitable electrical cable or wire, and the cables 22 of the pipe segments 20 are electrically connected together when the pipe segments 20 are joined, thus forming a single cable which runs along the whole length of the drill pipe 6. We refer to such a drill pipe as a wired drill pipe.

Some, but not necessarily all, of the pipe segments 20 are also provided with a pressure sensor 24 which may be positioned within the pipe segment 20 and electrically connected to cable 22 via an electrical connection 26. The pressure sensor can alternatively be positioned on the outside of the pipe segment 20, or there may be pressure sensors on both the inside and outside of the pipe segment 20. In one embodiment, a pipe segment provided with one or more pressure sensors is connected to the drill pipe 6 about every 400 metres, or between every 200 and 600 metres. In general, the pressure sensors can be positioned along the drill pipe with a spacing of between 100 metres and 1,000 metres.

Figure 1 shows four pressure sensors which are used in the method of calculating the total vertical depth of the well bore 2.

A manifold pressure sensor 30 measures the pressure, Pstp, in the stand pipe manifold.

An upper well bore pressure sensor 32 measures the pressure, P1, at an upper position in the well bore 2.

An lower well bore pressure sensor 34 measures the pressure, P2, at a lower position in the well bore 2.

A drill bit pressure sensor 36 measures the pressure, Pbit, at or near the drill bit 4.

The upper and lower well bore pressure sensors 32 and 34 are positioned in a part of the well bore 2 which is vertical or substantially vertical. This will usually be in the uppermost part of the well bore 2, which is commonly vertical in a directed well.

The method of calculating vertical depth is preferably performed in a no flow condition when the well fluid mentioned above is stationary or substantially stationary within the drill pipe 6, otherwise it is necessary to correct for drillstring frictional pressure. The condition of no flow occurs regularly and repeatedly as the well bore 2 is drilled. This is because, if for example 9 metre pipe segments are used, after every 27 metres of drilling, the drilling is stopped and the pumping of the well fluid is halted, to enable a further three 9 metre pipe segments to be attached to the drill pipe 6 at the top of the well. The method of calculating vertical depth can therefore conveniently be performed during these pauses when the well fluid is not being pumped.

The method first calculates an estimate of the average density of the well fluid within the drill pipe 6. This is done by using the upper and lower well bore pressure sensors 32 and 34 to measure pressures P1 and P2, and then applying the following formula: Davg = (P2 -P1)tg (h2 -hi) (Formula 1) where, Davg = average density of well fluid.

(h2 -hi) = difference in height between the upper and lower well bore pressure sensors.

g = acceleration due to gravity It will be appreciated that, because the upper and lower well bore pressure sensors 32 and 34 are positioned in a part of the well bore 2 which is vertical or substantially vertical, the difference in height between these sensors can readily and easily be determined. The difference in height is simply the distance between the sensors as measured along the well bore 2. For example, if the number of pipe segments 20 between the two pressure sensors 32 and 34 is known, then the difference in height between the two sensors is the number of pipe segments times the length of each pipe segment. The difference in height between the two pressure sensors 32 and 34 is preferably about 400 metres, or between 200 and 600 metres. If necessary, the elasticity of the drill pipe 6 can be taken into account when calculating the positions of the two pressure sensors 32 and 34.

The method then calculates the total vertical depth, Htvd, of the drill bit 4. This is done by using the manifold and dull bit pressure sensous 30 and 36 to measure pressures Fstp and Pbit, and then applying the following formula: Htvd = (Pbit -Pstp) / (Davg x g) (Formula 2) The stand pipe manifold 18 can be regauded as a reterence location, and the pressure, Pstp, in the stand pipe manifold can be regarded as a reference pressure, with Formula 2 being used to calculate the depth of the drill bit below the reference location.

However, a different reference location can be chosen. For example, if the depth of the upper well boue pressuue sensou 32 is known then the position of the upper well boue pressure sensor 32 can provide the reference location, and the pressure P1 at this sensor can form the reference pressure. In this case Formula 2 can be used to determine the depth of the drill bit below the uppeu well boue pressuue sensou 32.

We now describe an alternative embodiment in which only one of the two well bore pressure sensors 32 and 34 is present, and the other is not required. For example, this embodiment may use only the following three puessuue sensous: the manifold puessure sensou 30, the uppeu well bore pressure sensou 32 and the dull bit pressure sensor 36.

If the depth I height of well bore pressure sensor 32 is known (for example if the number of pipe segments between the surface and pressure sensor 32 is known) then the average density of the well fluid can be calculated in the same way as above, using the following foumula which is a modification of Foumula 1: Davg = (P1 -Pstp) / g (hi -hstp) (Formula 3) where, Davg = average density of well fluid.

(hi -hstp) = difference in height between the well bore pressure sensor 32 and the manifold pressure sensor 30.

g = acceleration due to guavity The depth of the drill bit is then calculated using Formula 2, as above.

In this embodiment the stand pipe manifold provides the reference location, and pressure in the stand pipe manifold is also used to determine the average fluid density.

The methods above assume that the average density calculated above represents a sufficient approximation for the fluid density between the manifold pressure sensor 30 and the drill bit pressure sensor 36.

The methods provide a way of calculating the total vertical depth, without integration of measured inclination. Furthermore the methods can provide regular updates of well depth as drilling proceeds.

Claims

CLAIMS: 1. A method of calculating vertical depth in a well bore containing a well fluid, the method comprising the steps of: a) measuring the pressure of said well fluid at a first location to produce a first pressure value; b) measuring the pressure of said well fluid at a second location to produce a second pressure value; c) determining the difference in height between said fiist and second locations; d) calculating a fluid density value for said well fluid using said first and second pressure values and said difference in height; e) measuring the pressuie of said well fluid at a thud location to pioduce a thud piessure value; f) determining a reference pressure, being the pressure of said well fluid at a reference location; g) determining the height of said reference location; and h) calculating the vertical depth of said third location using said fluid density value, said third pressure value and said reference pressure.
2. A method as claimed in claim 1, wherein said fluid density is calculated according to the following formula: D =(P2 -P1)! g(h2 -hi) where, D is said fluid density; P1 is said fiist pressure value; P2 is said second pressuie value; (h2 -hi) is the difference in height between said first and second locations; and g is the acceleration due to gravity.
3. A method as claimed in claim 1 or 2, wheiein said vertical depth is calculated according to the following formula: H = (P3 -Pref) I (Dx g) where, H is said vertical depth of said third location below said reference location; P3 is said third pressure value; Pret is said reference pressure value; and g is the acceleration due to gravity.
4. A method as claimed in any preceding claim, wherein said reference location is said first location, and said reference pressure is the same as said first pressure.
5. A method as claimed in any preceding claim, wherein said first location is in a stand pipe manifold.
6. A method as claimed in any one of claims ito 4, wherein said first location is in said well bore.
7. A method as claimed in claim 6, which further comprises determining the depth of said first location below the top of said well bore.
8. A method as claimed in any preceding claim, which further comprises determining the depth of said second location below the top of said well bore.
9. A method as claimed in any preceding claim, wherein the portion ot said well bore between said first and second locations is vertical or substantially vertical.
10. A method as claimed in any preceding claim, where said third location is within metres of a drill bit used for drilling said well bore.
11. A method as claimed in any preceding claim, which includes drilling said well bore using a drill bit attached to the end of a drill pipe, and positioning pressure sensors at regular intervals along said drill pipe.
12. A method as claimed in claim 11, when also dependent, directly or indirectly, on claim 5, which fuither comprises using at least some of said pressuie sensois to produce said second pressure value.
13. A method as claimed in claim 11, when also dependent, directly or indirectly, on claim 6, which fuither comprises using at least some of said pressuie sensois to pioduce said first and second pressuie values.
14. A method as claimed in any one of claims 11 to 13, wherein at least some of said pressure sensors are within said drill pipe.
15. A method as claimed in any one of claims 11 to 14, wherein at least some of said pressure sensors are positioned on the outside of said drill pipe.
16. A method as claimed in any one of claims 11 to 15, wherein said regular intervals are between 100 and 1,000 metres.
17. A method as claimed in any one of claims 11 to 16, wherein said regulal intervals are between 200 and 600 metres.
18. A method as claimed in any one of claims 11 to 17, wherein said drill pipe is a wired pipe.
19. A method as claimed in any one of claims 11 to 18, wherein said drill pipe is formed from pipe segments which are connected together as the well bore is drilled.
20. A method as claimed any preceding claim, wherein said pressure measurements are taken when said well fluid is not being pumped.