ARRANGEMENT AND METHOD FOR DETECTING FLUID INFLUX AND/OR LOSS IN A WELL BORE

Abstract

An arrangement and method for more accurately detecting well bore fluid kicks and/or losses by coupling a fluid flow measurement device to a substantially vertical tubular, such as a bell nipple or marine riser, to more accurately determine the flow rate of fluid flowing out of the well bore. Well bore fluid kicks and/or fluid losses are preferably detected by comparing the determined flow rate of fluid flowing out of the well bore and the flow rate of fluid injected into the well bore for any difference indicative of a well bore fluid kick or loss event.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates generally to an arrangement and method for detecting kicks (i.e., fluid influxes) and fluid losses from an oil and/or gas well. Specifically, the invention relates to an arrangement and method for accurately determining the fluid flow rate exiting a petroleum well by measuring fluid flow rate through a substantially vertical tubular, such as a bell nipple or marine riser, positioned near the top of the drill string.

2. Description of the Related Art

During the drilling of subterranean wells, a fluid (“mud”) is typically circulated through a fluid circulation system comprising a drilling rig and fluid treating equipment located substantially at or near the surface of the well. The fluid is pumped by a fluid pump through the interior passage of a drill string, through a drill bit and back to the surface through the annulus between the well bore and the drill string.

A primary function of the fluid is to maintain a primary barrier inside the well bore to prevent formation fluids from flowing to surface. A blow-out preventer (BOP), which has a series of valves that may be selectively opened or closed, provides a secondary barrier to prevent formation fluids from flowing uncontrolled to surface. To achieve a primary barrier inside the well bore using the fluid, the hydrostatic pressure of the fluid is maintained higher than the formation fluid pressure (“pore pressure”). Weighting agents may be added to the fluid to increase the fluid density, thereby ensuring that the hydrostatic pressure is always above the pore pressure. If, during drilling of the well bore, a zone is encountered having a higher pore pressure than the fluid pressure inside the well bore, an influx of formation fluid will be introduced into the well bore. Such occurrence is an undesirable event and is known as taking a “kick.” This same situation can occur not only during drilling, but also during completion, work-over or intervention.

When a kick is taken, the invading formation fluid and/or gas may “cut,” or decrease, the density of the fluid in the well bore annulus, such that an increasing amount of formation fluid enters the well bore. Under such circumstances, control of the well may be lost due to breach of the primary barrier. Such an occurrence may be noted at the drilling rig in the form of: (1) a change in pressure in the well bore annulus, (2) a change in fluid density, and/or (3) a gain in fluid volume in the fluid system tanks (“pit volume”).

Numerous arrangements and methods for detecting kicks (i.e., fluid influxes) and/or fluid losses while drilling wells or conducting well operations, workovers, completions, and interventions are known to those skilled in the art. Most of these arrangements and methods monitor the variation in fluid volume that is returned to the fluid/mud system tanks over time as an indicator of a kick or loss event. Using current arrangements and methods, however, this indicator is known to be inaccurate and may also be delayed, because a certain amount of volume is required for detection (i.e., typically over ten barrels). The oil and gas industry has attempted to develop improved methods of detecting kicks and losses in order to minimize their detection time as well as their fluid volume. Most of the improved methods measure the return flow rate at the return flow line and compare the measured return flow rate with the injected flow rate. Under normal circumstances the fluid flow rate into and out of the well bore should be the same (i.e., the differential flow rate should be zero). When a deviation is noted it is typically an indication of either a fluid gain or loss. The placement of flow rate meters on the return flow line from the well bore to measure the return fluid flow has been suggested but such measurements are not necessarily accurate because the return flow line is an open channel and is not always full of fluid. Therefore, the oil and gas industry has come to distrust rig kick detection systems based on this approach.

Another suggested approach is Managed Pressure Drilling (MPD). This method uses a closed-loop system and a flow rate meter on the return line to accurately measure the flow rate out of the well bore. The accuracy in such systems is very good, allowing the detection of a very small differential change in flow rate as well as the detection of the differential change almost immediately after the start of the kick or loss. The improved accuracy and speed of detection in MPD methods is due to the fact the well is closed and the fluid system is under pressure. The limitation posed by these systems is the amount of equipment that must be installed on a rig and kept for maintenance (e.g., to change the elements used on the rotating control heads for maintaining the well closed). This prevents the widespread use of these systems/methods, thus restricting their application to challenging wells, and only for the drilling phase. However, well control problems occur on a daily basis around the world. Such well control problems occur not just during drilling, but also during other operations.

Considering the aforementioned difficulties associated with the current strategies of detecting kicks (i.e., fluid influxes) and/or fluid losses while drilling wells or conducting well operations, workovers, completions, and interventions, an improved arrangement and method will provide several advantages.

3. Identification of Objects of the Invention

An object of the invention is to accomplish one or more of the following:

Provide an arrangement and method to improve detection of kicks and/or fluid losses from an oil and/or gas well;

Provide an arrangement and method for more accurately determining the flow rate of fluid flowing out of a well bore;

Provide an arrangement and method for measuring the flow rate of fluid flowing through a substantially vertical tubular positioned between a well blowout preventer and a return flow line;

Provide an arrangement and method for determining the flow rate of fluid flowing through a substantially vertical tubular while a drill string is positioned therein;

Provide an arrangement and method for measuring the flow rate of fluid flowing through a bell nipple; and

Provide an arrangement and method for measuring the flow rate of fluid flowing through a marine riser.

Other objects, features, and advantages of the invention will be apparent to one skilled in the art from the following specification and drawings.

SUMMARY OF THE INVENTION

The objects identified above, along with other features and advantages of the invention are incorporated in an arrangement and method for more accurately detecting kicks (i.e., fluid influxes) and/or fluid losses while drilling wells or conducting well operations, workovers, completions, and interventions. In a preferred implementation of the arrangement and method, a fluid flow measurement device is coupled to a substantially vertical tubular, such as a bell nipple or marine riser, disposed between the blowout preventer and the return flow line of a drilling system. The fluid flowing out of the well bore passes through the substantially vertical pipe prior to flowing to the surface fluid/mud tanks via the return flow line. Thus, the fluid flow rate measurement device is arranged and designed to measure the flow rate of fluid exiting the well bore. Measuring the fluid flow rate through the substantially vertical pipe facilitates the accurate measurement of the fluid flow rate, because the substantially vertical pipe is full of fluid when fluid is flowing therethrough and the flowing fluid has a hydrostatic pressure acting upon it due to the fluid above the measurement point.

The fluid flow measurement device of a preferred implementation is an ultrasonic flow rate meter having at least two transducers disposed on the outer surface of the substantially vertical tubular. The transducers are disposed on the substantially vertical tubular such that the ultrasonic signal, which is transmitted between the transmitter and the receiver of each transducer, passes through the annulus formed between the substantially vertical tubular and a drill string disposed therethrough. The transducers are preferably separated by a vertical distance greater than the length of a drill pipe connection, also known as a tool joint. The drill pipe connections of the drill string have a larger diameter than the surround drill pipe segments. Thus, when a drill string is disposed through the substantially vertical tubular, the annulus between the outer surface of the drill string and the inner wall of the substantially vertical tubular is reduced at the drill pipe connections. Therefore, a vertical separation between transducers of greater than the length of a drill pipe connection ensures that at least one of the transducers accurately measures the flow rate of the fluid flowing through the annulus (i.e., at least one transducer measures the annular flow rate that is not affected by a drill pipe connection). The transducers may be disposed about the substantially vertical tubular such that an ultrasonic signal is transmitted through the annulus on multiple sides of the drill string.

Kick or loss detection is preferably accomplished by comparing the flow rate of fluid pumped into the well bore via the drill string with the flow rate of fluid exiting the well bore through the return flow line. The flow rate of fluid pumped into the well bore is measured using another flow rate measurement device on the injection line. The flow rate of fluid exiting the well bore through the return flow line is measured by the fluid flow measurement device coupled to the substantially vertical tubular. When compared, the fluid flow into the well bore should be approximately equal to the fluid flow exiting the well bore for balanced well operations. Thus, any unexplained deviation or difference between the measured fluid flow rates is an indication that a fluid kick or fluid loss may have occurred.

BRIEF DESCRIPTION OF THE DRAWINGS

By way of illustration and not limitation, the invention is described in detail hereinafter on the basis of the accompanying figures, in which:

FIG. 1 illustrates a side view in partial cross section of a preferred implementation of the arrangement on a land rig which includes a flow rate measurement device coupled to the outer surface of a bell nipple above the blowout preventer and below the return flow line,

FIG. 2A is a side view in partial cross section of the bell nipple of FIG. 1 illustrating a drill string disposed therethrough and a flow rate measurement device coupled to an outer surface of the hell nipple,

FIG. 2B is a cross section view of the bell nipple of FIG. 2A illustrating the drill string disposed therethrough and the flow rate measurement device coupled to an outer surface of the bell nipple,

FIG. 2C is a cross section view of the bell nipple of FIG. 2A illustrating an alternative preferred implementation having the transducers of the flow rate measurement device disposed on the bell nipple such that an ultrasonic signal is transmitted through the annular space on two sides of the drill string, and

FIG. 3 illustrates a side view in partial cross section of a preferred implementation of the arrangement on an offshore rig which includes a flow rate measurement device coupled to the outer surface of a marine riser above the blowout preventer and below the return flow line.

DESCRIPTION OF THE PREFERRED IMPLEMENTATIONS OF THE INVENTION

A preferred implementation of the invention addresses one or more of the deficiencies of the prior art and incorporates at least one of the objects previously identified. Turning to FIGS. 1 and 3, a drilling system 70 is generally shown comprising a tubular drill string 30 (having, e.g., an outer diameter of 3.5 inches) suspended from a drilling rig 80, 90. The drill string 30 has a lower end which extends downwardly through a vertical tubular 40 (having, e.g., an inner diameter of 8 inches), through a blowout preventer (BOP) 50 (positioned below the vertical tubular 40) and into borehole/well bore 14. Borehole/well bore 14 is shown as having a casing 54 disposed below the wellhead 52. A drill bit 34 is coupled to the lower or distal end portion of drill string 30. A drill string driver or turning device 16, such as a top drive system (as shown) or a rotary drive system (not shown), is operatively coupled to an upper end of the drill string 30 for turning or rotating the drill string 30 along with the drill bit 34 to drill the well bore 14. A surface fluid/mud pump 72 pumps fluid from a surface reservoir 74 through a fluid injection line 76, through the upper end of the drill string 30, down the interior of drill string 30, through the drill bit 34 and into the borehole annulus 42. The borehole annulus 42 is created through the action of turning drill string 30 and attached drill bit 34 in borehole 14 and is defined as the space between the interior/inner wall or diameter of borehole 14 and the exterior/outer surface or diameter of the drill string 30. An annular space 44, 46 also exists between the drill string 30 and each of the interior/inner walls of the BOP 50 and vertical tubular 40.

Fluid pumped into the borehole annulus 42 through the drill string 30 flows upwardly through the borehole annulus 42. The BOP 50 is in fluid communication with the borehole annulus 42 and the fluid exits the borehole annulus 42 into the annular space 44 of the BOP 50. Substantially vertical tubular 40 has an inlet 36 coupled to blow-out preventer 50 and an outlet 38 coupled to return flow line 60. Fluid flowing through the annular space 44 of the BOP 50 enters the annular space 46 of the substantially vertical tubular 40 through inlet 36 and exits through the outlet 38 to the return flow line 60. The return flow line 60 is shown as a sub-horizontal tubular which provides fluid communication to mud tanks 74. As shown in FIGS. 1, 2A, and 3, the return flow line 60 is generally not full of fluid, and this condition causes inaccuracies in measuring the flow rate of fluid through the return flow line 60 using prior art devices and methods (not shown). On land rigs 80, the substantially vertical tubular 40, which is positioned above the BOP 50, is called the bell nipple (FIGS. 1, 2A, 2B and 2C). On off-shore rigs 90 (e.g., floating vessels), the substantially vertical tubular 40, which is positioned above the BOP 50, is a marine riser (FIG. 3).

As shown in FIGS. 1-3, a preferred implementation of the arrangement 10 (FIGS. 1 and 2A-2C), 12 (FIG. 3) and method includes a flow rate measurement device 20, such as a flow rate meter, coupled to a section of substantially vertical tubular 40 (i.e., a bell nipple as shown in FIG. 1 or a marine riser as shown in FIG. 3), below its outlet 38 to the return flow line 60. When the drill string 30 is disposed through the vertical tubular 40, through the BOP 50 and into the well bore 14, the flow rate measurement device 20 measures the flow rate of fluid being returned through the annular space 46 between the inner diameter of the vertical tubular 40 and the outer surface of the drill string 30. When no drill string 30 is present in the vertical tubular 40, the BOP 50 and the well bore, the flow rate measurement device 20 measures the flow rate of fluid being returned through the entire diameter of the vertical tubular 40. The flow rate measurement device 20 of a preferred implementation of the arrangement 10, 12 is an ultrasonic flow rate meter because of its flexibility to measure flow rate regardless of whether a drill string 30 is present. Those skilled in the art will readily recognize that other types of flow rate meters, such as a coriolis flow rate meter, a magnetic flow rate meter, and/or a laser-based optical flow rate meter, may be equally employed to measure the flow rate of fluid flowing through the vertical tubular 40. As is well known to those skilled in the art, an ultrasonic flow rate meter measures the velocity of the fluid flow based on several parameters including, but not limited to, the inner diameter of the tubular, the wall thickness of the tubular, its material of construction and the type of fluid flowing therethrough. As is readily known to those skilled in the art, the volumetric flow rate, Q, for the annular flow is calculated through the following equation: Q=v*π* (R_o²-R_i²), where v is the velocity as determined by the flow rate measurement device 20, R_o is the inner radius of the substantially vertical tubular 40, and R_i is the outer radius of the drill string 30.

As best shown in FIG. 2A, the drill string 30 is comprised of drill pipe segments 28 coupled via drill pipe connections 32. The drill pipe connections 32 have larger outer diameters than the outer diameters of the adjacent drill pipe segments 28. Thus, when the drill string 30 is disposed within the vertical tubular 40, an annular space 46 is created between the outer surface of the drill string 30 and the inner diameter of the vertical tubular 40. However, the annular space 46 surrounding the drill pipe connections 32 is less than the annular space 46 surrounding the drill pipe segments 28 between drill pipe connections 32. Because there is less annular space 46 surrounding the drill pipe connections 32, the fluid velocity through the annulus 46 of the vertical tubular 40 must increase in the vicinity of the drill pipe connections 32 in order to maintain a constant volumetric flow rate through the vertical tubular 40. Therefore, coupling a flow rate measurement device 20, such as an ultrasonic rate meter, having a single transducer 22 (i.e., a transmitter and receiver pairing) to the vertical tubular 40 will not always provide an accurate measurement of fluid flow rate through the vertical tubular 40. This is because the drill string 30, and consequently the drill pipe connections 32, move up and down within the vertical tubular 40 during various operations. Thus, when a drill pipe connection 32 moves into the section of the vertical tubular 40 in which the single transducer 22 is disposed, the ultrasonic flow rate meter 20 measures an increased fluid velocity due to the reduced annular space 46 between the interior/inner wall of the vertical tubular 40 and the outer surface of the drill pipe connection 32. Because the ultrasonic flow rate meter 20 does not recognize the reduced annular space 46 caused by the drill pipe connection 32, the ultrasonic flow rate meter 20 calculates the volumetric fluid flow rate based upon the measured, increased fluid velocity and the annular space dimensions as if the measurement was conducted between drill pipe connections 32.

As best shown in FIG. 2A, the ultrasonic flow rate meter 20 of preferred implementation 10 has two transducers 22, 26 (i.e., an upper transmitter/receiver pairing 22 and a lower transmitter/receiver pairing 26) disposed about the outer surface of vertical tubular 40. The two of more transducers 22, 26 of the ultrasonic flow rate meter 20 are not disposed at the same vertical position on the outer surface of vertical tubular 40. Instead, the plurality of transducers 22, 26 are separated by a vertical distance or separation 24 with respect to each other, which is designed to be at least the length/distance of a drill pipe connection 32. This distance or separation 24 permits at least one of the transducers 22, 26 to measure the fluid velocity in the annular space 46 at a point between the drill pipe connections 32 as the drill string 30 moves up and down during drilling and/or other operations. Thus, at least one of the transducers 22, 26 measures a fluid velocity and calculates a volumetric fluid flow rate that is not affected by the reduced annular space 46 due to a drill pipe connection 32.

As best shown in FIG. 2B, the upper transducer 22 (i.e., a transmitter and receiver pairing) is disposed about the vertical tubular 40 such that the transducer transmits an ultrasonic signal 18 (i.e., shown by the broken line between transmitter and receiver) through the annular space 46 of the vertical tubular without passing through the drill string 30. The lower transducer 26 (i.e., a transmitter and receiver pairing) is analogous to the upper transducer but is disposed a vertical distance 24 (FIGS. 1, 2A and 3) below the upper transducer 22 and thus can not be seen in FIG. 2B. The upper and lower transducers 22, 26 may be on the same side of the drill string 30, as shown in FIGS. 1, 2A, 2B, and 3, or on opposite sides of the drill string 30 (FIG. 2C) such that the transducers 22, 26 transmit an ultrasonic signal 18 through the annular space 46 on two sides of the drill string 30. One skilled in the art will readily recognize that a plurality of transducers (not shown) may be disposed about the vertical tubular 40 such that an ultrasonic signal 18 is transmitted through the annular space 46 around the entire circumference of the drill string 30. Again, at least two of the transducers 22, 26 are preferably separated by a vertical distance 24 relative to the drill string 30.

As illustrated in FIGS. 1, 2A and 3, when fluid is flowing through the vertical tubular 40 and into the return flow line 60, the vertical tubular 40 will be full of fluid. The fluid flowing through the vertical tubular 40 creates a hydrostatic pressure that acts downwardly towards the fluid exiting the well bore 14. The fluid also imparts some friction loss pressure when flowing. By coupling the flow rate measurement device 20 to the vertical tubular 40, the flow rate measurement device 20 measures the fluid flowing through vertical tubular 40 under hydrostatic pressure (i.e., the hydrostatic pressure of the fluid in the vertical tubular 40 above the transducers 22, 26 of the flow rate measurement device 20). An advantage to measuring the fluid flow under hydrostatic pressure is that, as known to those skilled in the art, such an arrangement improves the accuracy of and accelerates the response time for kick or loss detection.

Kick or loss detection is preferably accomplished by comparing the flow rate of fluid pumped into the well bore 14 via injection line 76 and drill string 30 with the flow rate of fluid exiting from the well bore 14 through the return flow line 60. The flow rate of fluid pumped into the well bore 14 is typically measured/determined using another (or second) flow rate measurement device 78 on the injection line 76. Such flow rate measurement device 78 may be selected from any type known to those skilled in the art including, but not limited to, a coriolis flow rate meter, an ultrasonic flow rate meter, a magnetic flow rate meter, and/or a laser-based optical flow rate meter. Alternatively, the strokes of the surface fluid/mud pump 72 as a function of time can be measured and used to compute the flow rate of fluid pumped into the well bore 14. As previously described, the flow rate measurement device 20 coupled to the substantially vertical tubular 40 is used to measure/determine the flow rate of fluid exiting the well bore 14. If the well is balanced, the fluid flow into the well bore 14 should be approximately equal to the fluid flow exiting the well bore 14 (or have a difference that is approximately equal to the production rate during underbalanced drilling operations). Therefore, upon comparison, any unexplained deviation or difference between the measured fluid flow rates is an indication that a fluid kick or fluid loss may have occurred. A conventional response to any indication of a fluid kick or fluid loss is to close the BOP 50, thereby closing the well bore annulus 42 from atmosphere. One or more of the implementations described herein permit corrective action to be taken sooner, thereby reducing the chance of a loss of well control and its potential adverse effects.

The Abstract of the disclosure is written solely for providing the United States Patent and Trademark Office and the public at large with a means by which to determine quickly from a cursory inspection the nature and gist of the technical disclosure, and it represents one preferred implementation and is not indicative of the nature of the invention as a whole.

While some implementations of the invention have been illustrated in detail, the invention is not limited to the implementations shown; modifications and adaptations of the disclosed implementations may occur to those skilled in the art. Such modifications and adaptations are in the spirit and scope of the invention as set forth in the claims hereinafter:

Claims

1. An arrangement (10, 12) for detecting a well bore fluid kick or loss comprising:

a drill string (30) having a drill bit (34) at a distil end portion arranged and designed to drill a well bore (14), said drill bit creating a well bore annulus (42) between said drill string and an inner surface of said well bore as said well bore is drilled;

a blowout preventer (50) in fluid communication with said well bore annulus and arranged and designed to close said well bore annulus from atmosphere in response to an indication of a fluid influx event;

a substantially vertical tubular (40) fluidly coupled to said blowout preventer and in fluid communication therewith, said substantially vertical tubular having a flow line (60) fluidly coupled to an outlet (38) thereof, said substantially vertical tubular and said flow line arranged and designed to carry fluid exiting said well bore annulus through said blowout preventer; and

a flow measurement device (20) coupled to said substantially vertical tubular between said blowout preventer and said flow line, said flow measurement device arranged and designed to determine a flow rate of fluid flowing through said substantially vertical tubular.

2. The arrangement of claim 1 wherein,

said substantially vertical tubular is a bell nipple.

3. The arrangement of claim 1 wherein,

said substantially vertical tubular is a marine riser.

4. The arrangement of claim 1 wherein,

said flow measurement device is an ultrasonic flow rate meter.

5. The arrangement of claim 4 wherein,

said ultrasonic flow rate meter has at least two transducers (22).

6. The arrangement of claim 5 wherein,

said ultrasonic flow rate meter has two transducers (22) which are disposed on said tubular and separated from each other by a vertical distance (24).

7. The arrangement of claim 6 wherein,

said vertical distance is greater than a length of a drill pipe connection (32).

8. The arrangement of claim 1 further comprising,

another flow rate measurement device (78) coupled to a fluid injection line (76) in fluid communication with said drill string disposed in said well bore, said another flow rate measurement device arranged and designed to determine another flow rate of fluid flowing through said fluid injection line.

9. A method for detecting a well bore fluid kick or loss comprising the steps of:

coupling a flow rate measurement device (20) to a substantially vertical tubular (40), said substantially vertical tubular fluidly coupled to a blowout preventer (50) which is in fluid communication with a well bore (14), said substantially vertical tubular having a flow line (60) coupled to an outlet (38) thereof, said substantially vertical tubular and said flow line arranged and designed to carry fluid exiting said well bore through said blowout preventer, said flow rate measurement device arranged and designed to determine a flow rate of fluid flowing through said substantially vertical tubular between said blowout preventer and said flow line;

determining said flow rate of fluid flowing through said substantially vertical tubular using said flow rate measurement device coupled to said substantially vertical tubular between said blowout preventer and said flow line; and

comparing said determined flow rate of fluid flowing through said substantially vertical tubular and a determined flow rate of fluid flowing into said wellbore for any difference indicative of a well bore fluid kick or loss.

10. The method of claim 9 wherein,

said substantially vertical tubular is a bell nipple.

11. The method of claim 9 wherein,

said substantially vertical tubular is a marine riser.

12. The method of claim 9 wherein,

said flow rate measurement device is an ultrasonic flow rate meter.

13. The method of claim 12 wherein,

said ultrasonic flow rate meter has at least two transducers (22).

14. The method of claim 13 wherein,

said ultrasonic flow rate meter has two transducers (22) which are disposed onto said substantially vertical tubular and separated from each other by a vertical distance (24).

15. The method of claim 14 wherein,

said vertical distance is greater than the length of a drill pipe connection (32).

16. The method of claim 9 further comprising the steps of,

coupling another flow rate measurement device (78) to a fluid injection line (76) in fluid communication with a drill string (30) disposed in said well bore, said another flow rate measurement device arranged and designed to determine another flow rate of fluid flowing through said fluid injection line into said drill string, and

determining said another flow rate of fluid flowing through said fluid injection line into said drill string using said another flow rate measurement device, and wherein

said determined flow rate of fluid flowing into said wellbore is equal to said another flow rate of fluid flowing through said fluid injection line into said drill string.

17. An arrangement (10, 12) for measuring flow rate of fluid exiting a well bore, said arrangement comprising:

an ultrasonic flow rate meter (40) having at least two transducers (22) disposed about a substantially vertical tubular (40), said substantially vertical tubular coupled to a wellhead (52) and in fluid communication with a well bore (14), said at least two transducers having a vertical separation (24) therebetween and arranged and designed to determine a flow rate of fluid passing through said substantially vertical tubular from said well bore.

18. The arrangement of claim 17 wherein,

said substantially vertical tubular is a bell nipple.

19. The arrangement of claim 17 wherein,

said substantially vertical tubular is a marine riser.

20. The arrangement of claim 17 wherein,

said vertical separation is greater than the length of a drill pipe connection (32).