JPH0514236B2 - - Google Patents

Description

DETAILED DESCRIPTION OF THE INVENTION The present invention relates to testing of oil and gas exploration wells and equipment used in such testing.

In determining the value of oil and gas exploration wells, one of the important parts of data collection is the drill stem test (hereinafter referred to as DST). DST is the production of reservoir fluids under carefully controlled conditions and provides information about the performance of producing wells at exploration sites. In DST, drill pipe struts are used as temporary production pipes.

During drilling of a wellbore, the weight of the column of drilling water within the wellbore prevents formation fluids from entering the wellbore under their own pressure. To allow test production of fluid through the drill pipe from the selected formation in a safe manner, the column of drill water must remain in place around the drill pipe.

The inflatable packer, which is part of the drill pipe column, provides a seal between the drill pipe and the wellbore sidewall, which may be exposed rock or steel casing. To enable production, the drill pipe must contain a fluid that has a specific gravity less than the tap water and provides a hydrostatic pressure that is less than the formation pressure.

The most useful data obtained from DST are the pressures associated with the artesian well and, most importantly, measurements of the rise in reservoir pressure when the well is sealed and the reservoir is stable. The latter data give direct information on the extent of damage to the permeability of the reservoir rock and the permeability in the immediate vicinity of the wellbore.

In order to provide a basis for correct judgment, the pressure measurements must be very accurate and must be carried out in the downhole of the wellbore to prevent the inflow of fluid into the wellbore or the outflow of fluid after surface sealing. must be able to be sealed tightly. The movement of fluid in a long vertical wellbore after sealing causes transient pressure changes that obscure the desired reservoir effect, ie, the post-sealing reservoir pressure.

Conventional DST equipment utilizes the action of a puncher placed at a point fairly close to the bottom end of the drill string. A bottom hole sealing valve is located at the top near the bottom end. Bourdon
A clockwork recorder of type Tube type gauge is placed in a protective holder below the sealing valve to view the reservoir artesian and sealing pressure. A similar clockwork recording thermometer provides temperature data.
This was the state of the technology about four years ago.

This device had the following problems.

(a) Gauges that were inaccurate and insensitive required lengthy testing to provide data that could be reliably determined.

(b) The engineer conducting the test did not know the condition of the downhole or whether the gauge was working.

(c) The gauge had been inserted into the DST equipment which was subjected to very rough handling during the insertion of the drill pipe.

With the advent of electrically actuated pressure gauges, accuracy has been greatly improved. However, this pressure gauge had the major drawback that it had to be connected by a conductive wire and therefore could not be passed through a downhole sealing valve which would obviously have to be cut. .

As another example of the prior art, electrical meters with self-recording devices have recently become available. It is designed so that it can be installed within a conventional instrument holder. This device has a significant drawback in that it does not provide information to the technician while performing the test, forcing the technician to act blindly without knowing exactly what is happening in the downhole. ing.

In producing wells where sealing of the downhole is usually not possible, electrically operated instruments, usually wired, are routinely used. This requires that post-wellbore artesian effects, ie changes in reservoir pressure after sealing of the wellbore, be carefully monitored; this data is ignored and only the above-mentioned reservoir effects are taken into account. This has the disadvantage that it is very time consuming in low productivity gas and oil wells where the post-artistic effect is very long and the test has to be stretched out.

The most recent development that has turned electrical meters into practical tools for DST is the Flopetrol/Dowell
This is the "SPRO" device developed by Schumberger. This device uses a gauge built into the bottom hole sealing valve. The gauge is configured to measure pressure below the valve by communicating pressure to a gauge located above the closure.

Such a meter and seal assembly is inserted as part of a drill pipe column, and electrical connections are made by wire after the meter and seal assembly is in place. This has the following drawbacks.

(a) The sealing valve assembly inserted as part of the drill pipe column is sophisticated and must be tested by a drilling specialist. This, as well as the tools themselves, requires a great deal of expense.

(b) Electrical connections to the gauge must be made in the wellbore fluid and are generally unreliable.

(c) Flow through the valve is restricted by a narrow passage approximately 2.00 cm in diameter.

SUMMARY OF THE INVENTION It is an object of the present invention to provide a well testing device that does not have the disadvantages associated with devices using wires or special pipes, and a method for testing wells using such a device. .

In accordance with the present invention, one or more wellbore wells in which the wellbore fluid pressure is lower than the associated reservoir pressure, thereby allowing the wellbore fluid to flow upwardly through the wellbore toward the surface. A method of performing the specified test is provided. The method includes providing a hollow member in a wellbore containing equipment for making measurements and collecting data from the test, wherein a fluid flowing upwardly through the wellbore has a path including a passageway through at least a portion of the hollow member. and the fluid is in direct communication with the device within the hollow member, and the specified This is a method of conducting a test.

The apparatus for use in the method of testing a wellbore according to the invention is an assembly adapted to be received within a hole of a drill string and configured to include a data acquisition device, the assembly comprising a hollow a member, the hollow member having a longitudinally spaced inlet and an outlet for permitting passage of fluid from the wellbore through the inlet to the lower end of the hollow member, the hollow member also closing the outlet; a closure device movable relative to the upper part of the hollow member for the purpose of
a device for actuating a closure device to close the outlet; and a device for sealing the annular space between the lower end of the hollow member and the wall of the pipe in the region between the inlet and the outlet. , characterized in that the measuring device is arranged within the hollow member and is in direct communication with the fluid in the region between the inlet and the outlet.

Referring to FIG. 1, an assembly placed within a bore of a drill pipe 1 includes a hollow member 2 and an internal closure device 3 forming a sliding seal within the hollow member 2. The closure device 3 has a cylindrical hollow section 5 at the lowermost end.
It includes a cylindrical plug part 4 extending up to .

The hollow member 2 is provided with longitudinally spaced ports 6, 7 which are formed in the wall of the hollow member 2 in the form of slots. The lower mouth 7 forms the inlet for the fluids of the wellbore, while the upper mouth 6
forming an outlet for the fluid;

The hollow member 2 is closed at its lowermost end 8 and is provided there with an instrument enclosure 9 for monitoring the fluids in the wellbore. The instrument package 9 contains a pressure measuring device, a thermometer and a flow meter. The closure device 3 has an actuation device 10 (shown schematically) located above the closure device 3 in the hollow member 2 and secured thereto.
The actuating device 1 is configured to be actuated by the actuating device 1.
0 has a ram 11 driven hydraulically/pneumatically, hydraulically or electrically. The drive of the ram 11 is operated remotely via a cable (not shown) from the ground.

A cable (not shown) from the instrument package 9 is
It is extended to the surface through an airtight conduit (not shown). The conduit may be arranged in a vertical recess in the inner or outer wall of the hollow member 2 or in a second
Similar to what is shown in the figures, the closure device 3 and the ram 11 may extend upwardly through the bore of the hollow member 2.

In use, the ram 11 is actuated to move the closure device 3 downwardly against the action of a return spring 12 arranged above the closure device 3 and surrounding the ram 11 . Due to the downward movement of the closure device 3, the hollow member 5
covers the outlet 6 and closes the lower part of the hollow member 2. The closing position of the closing device 3 is shown in FIG. 1 by dotted lines. In this state, the reservoir pressure, or confinement pressure, at which the fluid in the wellbore is at rest, can be measured. When the actuating device 10 is released, the ram 11 is moved by the return spring 12
is moved upwardly by the actuation of , returning the closure device 3 to its original position, whereby the outlet 6 is uncovered and reopened. In this state, it is possible to measure the fluid pressure while the fluid in the well is flowing. In the absence of a control signal to the actuating position 10, the upward movement of the closure device 3 takes place automatically.

In order to seal off the annular space between the hollow member 2 and the wall of the pipe 1, an inflatable packer 13 is provided in the area between the ports 6 and 7. The pack car 13 is preferably inflated hydraulically by remote control from the ground.

The closure device 3 may be of a different form to that shown in FIG. For example, the closure device 3 may simply be a hollow cylinder. In yet another embodiment, it may be a hollow cylindrical body with a mouth corresponding to the outlet 6 of the hollow member 2. In this case, when the closure device 3 is in a longitudinal position and the outlet 6 is aligned with the mouth of said hollow cylinder, the outlet 6 opens, while in the other longitudinal position the closure device 3 is displaced from its initial position. In position , the outlet 6 is closed by the wall portion of the hollow cylinder.

As a further alternative, the closure device 3 may be a hollow cylinder with circumferentially spaced ports that can be aligned with the outlets 6 at certain locations and open them. In the other position, where the hollow cylinder has been rotated through a certain angle of rotation, the outlet 6 is closed by the wall of the hollow cylinder. In this case, the actuating device must cause a rotational movement about the axis of the cylinder rather than a longitudinal sliding vibration of the cylinder.

In FIG. 2, the same parts as in FIG. 1 are given the same reference numerals. The closure device includes an outer sleeve 14 that sealingly slides over the hollow member 2.
has. The upward movement of the outer sleeve 14 is caused by the shoulder 1 of the hollow member 2 formed between the lower part 16 and the upper part 17 of a larger diameter than the lower part 16.
5. The partition wall 18 divides the hollow member 2 into an upper chamber 19 and a lower chamber 20, the lower chamber 20 having openings 6,7.

The outer sleeve 14 is connected to the piston 12 of the ram 22 and slides over the hollow member 2. piston 2
1 has a radially extending portion 23 through a longitudinally elongated hole in the wall of the hollow member 2, which radially extending portion 23 is connected to an outer sleeve 14 which is Can be moved relative to the hole. The ram 22 is actuated by fluid introduced under pressure into the upper part 24 of the upper chamber 19.
A fluid reservoir and a fluid control valve (not shown) are located in the upper chamber 1.
9 in the upper part 24.

A gas-tight conduit 25 extends from the ground through the central bore of the ram 22 in the hollow member 2, through the piston 21 and the bulkhead 18. Conduit 25 includes fluid reservoirs and control valves, as well as cables (not shown) for remote control of instrument package 9.

Movement of the piston 21 downwards from the position shown in FIG. The ram 22, the piston 21 and the sleeve 14 are urged upward by the action of the return spring 12 which is compressably disposed therebetween.

Actuation can be hydraulic/pneumatic, hydraulic or electromechanical.

A DST tool according to the invention is inserted into a wellbore by one of the optional actuation sequences. First, in the sealing mode, a conventional downhole sealing valve is inserted as part of the drill string to prevent fluid from rising through the hollow member 2, and subsequently the DST tool is inserted under the hollow member 2. It is lowered into the hole. Flow control is provided by the DST tool valve assembly in opening the lower hole sealing valve.

Other ways to position the DST tool are to insert a drill string and insert an open ended drill string below the hole.

The deep water column in drill pipe 1 is filled with seawater,
A lower specific gravity fluid such as diesel oil or nitrogen is substituted, so that the DST tool is submerged in the lower specific gravity fluid. After installing the DST tool, fluid control is again provided by the tool's valve assembly.

The use of the test tool according to the invention has many technical advantages. One example is that the barf ration spacing of the well wall for testing is selective;
It is possible to achieve the reservoir thickness and agglomeration state in small steps and to evaluate their aggregation. Downhole flow meters can be activated to measure the flow from each group of perforations.

The invention can be advantageously used when drilling wells. This is not important for high-producing oil and gas wells, but especially for inferior wells with two-layer flow, e.g. gas-oil-water, after sealing and residual flow, the wellbore Contents are redistributed to high-capacity wells, obscuring valuable data. In order to utilize the equipment of the invention in existing installations, it is necessary to prepare in advance a special nipple, which is an integral part of the tube string and must be inserted when the wellbore is completed. . Existing wells without modified tube strings cannot be tested with existing equipment. In contrast, use of the present invention does not require modification of the production line and can be used in already existing wells.

According to the present invention, the test device is not normally inserted together with the drill string, so there is little risk of damage that conventional DST tools are subjected to when inserting the drill string.

Additionally, because the measurement device is in direct communication with the wellbore fluid being tested, anomalies such as temperature changes and slow pressure changes during sealing are eliminated. In this way, the measurement results can be used quickly and accurately, saving time and money.

[Brief explanation of drawings]

FIG. 1 is a vertical cross-sectional view of an embodiment of the invention;
FIG. 2 is a vertical cross-sectional view of another embodiment of the invention. 1...Drill pipe, 2...Hollow member, 3...
Internal closure device, 6, 7 points...mouth, 11...ram,
12... Return spring, 14... Outer sleeve, 21...
...Piston, 25... Conduit.

Claims (1)

Claims: 1. 1 or more for wellbore where the pressure of the wellbore fluid is less than the associated reservoir pressure, thus allowing the wellbore fluid to flow upwardly from the wellbore toward the surface. A method of carrying out the above specified tests, characterized in that a hollow member containing equipment for measurements and data acquisition from said measurements is placed in a wellbore so that fluid flowing upwardly through the wellbore a passageway including a flow path through at least a portion of the member, wherein fluid is in direct communication with the device within the intermediate member, and the fluid is in direct communication with the device through or from the hollow member; A method for testing a wellbore, characterized in that the specified test is carried out while preventing leakage. 2. The method of claim 1, wherein the wellbore is the region formed by the inner bore of the inserted pipe string. 3. The hollow member is contained within an assembly having longitudinally spaced inlets and outlets to permit wellbore fluid to flow from the inlet to the lower end of the hollow member, the assembly further comprising an outlet; a closure device movable relative to the upper part of the hollow member to close the outlet, a device for actuating said closure device to close the outlet; and a device for sealing the annular space between the wellbore wall and the wellbore wall. 4. In an assembled well test device adapted to be received in a bore of a drill string and configured to include a data acquisition device,
The assembly includes: a hollow member having longitudinally spaced inlets and outlets; a closure device movable relative to an upper portion of the hollow member to close the outlet; and the closure device to close the outlet. and a sealing device for sealing the annular space between the lower end of the hollow member and the wall of the pipe in the area between the inlet and the outlet, the data acquisition device comprising: A wellbore testing device, characterized in that it is located within a hollow member at a position in direct communication with a fluid in a region between an inlet and an outlet. 5. The device of claim 4, wherein the closure device is contained within a hollow member for movement within the hollow member to close the outlet. 6. Apparatus according to claim 5, wherein the closure device is longitudinally slidably disposed within the hollow member, and wherein the drive device is adapted to longitudinally slide the closure device. 7. The closure device includes a sleeve member for the hollow member, the sleeve being longitudinally slidable over the upper portion of the hollow member to close the outlet, and the drive device longitudinally sliding the sleeve. The apparatus according to claim 4, which has become as follows. 8. A device according to any one of claims 4 to 7, wherein the closure device is an inflatable wad. 9 Claims 4 to 8 in which the drive device is operated pneumatically, hydraulically/pneumatically, hydraulically or electromechanically.
10. An oil and gas well incorporating the device according to claim 4.