GB2443675A

GB2443675A - A method of providing a productivity index profile over a length of a well

Info

Publication number: GB2443675A
Application number: GB0620987A
Authority: GB
Inventors: Garth John Naldrett; Sam Simonian
Original assignee: FLOSOFT Ltd
Current assignee: FLOSOFT Ltd
Priority date: 2006-10-23
Filing date: 2006-10-23
Publication date: 2008-05-14
Anticipated expiration: 2026-10-23
Also published as: GB0620987D0; GB2443675B

Abstract

A method of providing a productivity index (PI) profile 26 over a length of a producing or injection well. Preferably the PI profile is obtained by deriving multiple values of the PI (approximately every 30 cm) from a flow profile 22 along the said length, the flow profile itself being derived from distributed temperature measurements along the length. The PI index at a position in the wellbore is preferably calculated from the derived flow rate, the known reservoir pressure and the known wellbore pressure at that position. A second aspect provides for a method of managing oil well production using the above method, optionally with the stimulation of oil production whilst monitoring the PI profile. A further aspect provides a method wherein the reservoir pressure can be monitored by assuming a constant PI so that a decreasing flow rate indicates a drop in reservoir pressure.

Description

* * 2443675 Oil Welt Management The present invention provides for a

method of determining productivity index data, and reservoir pressure data in relation to a producing, or injection, well.

Various techniques for monitoring and/or estimating the performance of oil wells have been employed and which take account of factors such as temperature, reservoir pressure and rock permeability.

The use of temperature measurements to calculate flow and petrophysica! data has been known for many years and date back to 1904 when first proposed by the Russian Professor D.V. Golubyatnikov. It has also been long understood that the temperature measurement could be inverted to create more meaningful information about the well performance. In October 1973, M.R. Curtis and E.J. Witterholt published the paper "Use of the Temperature Log for Determining Flow Rates in Producing Wells" at the Annual Fall Meeting of the Society of Petroleum Engineers, Paper No SPE 4637, explaining how temperature profiles could be inverted into a flowing profile. At that time Curtis, Witterholi and others acquired temperature profiles by way of performing production logs, or interventions, into the oil well. Such techniques provided a single snapshot in time of the flowing temperature.

Since I 994, fibre optic Distributed Temperature Measurement, has been employed in oil field environments and advantageously allows the weilbore temperature profile to be continuously measured over time. It has also been shown how information from Distributed Temperature measurements can be used to calculate flow rate from a well.

Such techniques showed that the temperature profile along a length of a conduit could be S... . . used to determine the rate of fluid flow in that conduit. S... * .

However, such known measurements alone are disadvantageously limited, and serves to restrict the manner in which effective oil well management can be achieved. S... * . S S. S

*.SS.. * S 1

The present invention seeks to provide for a method of producing Productivity Index (P1) data having advantages over known such methods.

According to a first aspect of the present invention, there is a method of providing productivity index data for a producing or injection well, wherein the said data is provided as a productivity index profile over a length oithe well.

The present invention shows that by determining the source(s) and quantity of flow into a conduit such as a vellbore, it proves possible to develop a method to accurately determine the pressure driving the flow into the conduit and, importantly, employing a method of determining a P1 profile along the wellbore, improves this evaluation.

Advantageously, the P1 profile is obtained through the calculation of multiple values of the P1 along the said length of the well.

Preferably, the multiple values of the P1 are calculated in the order of every foot i.e. about every 30 cm along the said length of the well.

As a further feature, the P1 profile can be calculated in a manner allowing monitoring of changes in the profile over time.

A particular feature ot' the present invention is that the P1 profile is derived from temperature profile data for the well.

In particular, the temperature profile data is obtained for the production, or as appropriate the injection, interval. **..

The temperature profile is advantageously obtained by means of a distributed I...

temperature measurement which, advantageously, is provided by way of a fixed installation. * . * ** S

S * 2

Preferably, the method includes the step of obtaining flow profile data, obtained from the said temperature profile data, and from which the P1 profile is calculated.

Of course, it should he appreciated that the temperature profile data can be inverted so as to provide for the flow profile data. The art of performing the inversion of the acquii-ed temperature data into flow profile data is largely explained in the aforementioned paper by Curtis and Witterholt the full content of which is incorporated herein by reference.

Where the flow originates from two or more producing intervals the temperature at the confluence of the two fluid streams is a reflection of the percentage of flow between the two streams. in a vertical oil well the flow rate can be calculated using information about the geothermal gradient at the position of inflow, temperature just below the flow confluence and temperature of the commingled stream. Mathematically thc relationship can be described as illows:

-____

QLoer -T 1B C Where: Qiot'er Flow from the lower zone QT0l Combined flow from the upper and lower zones Tc Temperature of the commingled flow TG Geothermal temperature at the location of inflow T8 Temperature of flow below point of inflow *S..

Understanding the impact of inflow on the temperature allows calculation of the inflow at every point along in the welibore. Having calculated the flow profile (Q'1) the P1 profile, as we have defined in this invention, can be obtained from the following relationship: *.S. * * S S. *

**SS.. P1=

" (pa,,, P) Where Pl Productivity Index at position n in the weilbore Q' Flow rate from location ii in the wellbore Pci Reservoir pressure at position n along the welibore p Welibore pressure at position ii along the wellbore It should also be appreciated that the present invention can provide for an improved method of managing oil well production including the above-mentioned method of determining productivity index data.

As noted, the flow profile related data Q is derived from the inverted temperature profile data such that, in effect, the P1 value at position n in the weilbore clearly has its derivatives in the temperature data at that position, and so the PT profile is readily obtained from temperature measurements.

From the above, it will be appreciated that the management of oil well production can then be achieved through monitoring variation in performance along the said length of the well, and/or over a particular period.

Further, the method of managing oil well production can include the step of stimulating oil production, while monitoring any changes to the P1 profile that result from ** such stiiiiulation. * * * **. *** * * S * .5.

It should of course be appreciated that the present invention can provide for a computer program element containing instructions which, when loaded on a computer *: serve to control the computer to perform the method of providing profile index data as defined above. S... * S S * S

* S..S5 * * As one Further feature, the present invention relates to a computer readable media device including the computer program elements defined above, such device comprising magnetic, optical and/or memory storage med ía.

Yet further, the present invention can provide for computer hardware device arranged to run in accordance with a computer program element as defined above.

According to a fi.irther aspect of the present invention, there is provided a method of monitoring change in a reservoir pressure profile within a producing or injection well, and including the step of monitoring the change in weilbore temperature profile over a period of time.

Advantageously, the change in wellbore temperature profile converted into a flow profile from which changes in the reservoir pressure profile can be identified.

As will therefore be appreciated the present invention relates to a method of determining reservoir pressures and/or a P1 profile in a producing or injecting well. In particular the invention is concerned with the accurate calculation of such parameters along the length of the welibore by using the measured temperature profile along the production or injection interval either continuously or at multiple points in time.

Knowledge of the distribution of' reservoir pressure and P1 profile can then be used for the efficient management of oil wells and the fields in which they are located. The reservoir pressure distribution is a good indicator of reservoir connectivity and reservoir Potential. * .** ***S * .

*S.. . The P1 indicates well performance potential. *.** * S **S.

Significant changes in the productivity index over time highlight the requirement for well stimulation to improve well performance. * * * ** *

* 55S5. * * * 5

Through accurate measurenlent of temperature, and accurate inversion of this temperature to flow, pressure and P1, significant improvements can be made in the production rate and overall recovery from oil wells and fields.

Improvements that can be made relate to the better management of water or gas injection, improved placement of infill wells, improved well designs, improved well stiniulatioii treatment and better management of zonal production using inflow control devices, but of course this list is not exhaustive.

The invention is described further hereinafter, by way of example only, with reference to the accompanying drawings in which: Fig. I is a schematic diagram of rock formation with a producing welibore provided therein; and Fig. 2 is a flow diagram illustrating a procedure for monitoring change in reservoir pressure and change in productivity index according to an embodiment of the present invention.

The concept of a P1 was first mentioned by T.V. Moore in 1930 in a paper Definitions of potential productions of wells without open flow tests".

At that time, oil wells were traditionally flowed at their maximum rate in order to determine their production potential. However, this was not always practical and could result in permanent weilbore damage. As an alternative the concept of a PE was found to be more useful and allowed an understanding of the relationship between flow and back Iressure. The P1 specifies the relationship between flow (measured in barrels per day) and pressure drop between the reservoir and the weilbore (measured in psi). *.S. * * ** **

From its origins as a means for determining the production potential for the entire well, the P1 is given as a single value for the well. **** * S 0 ** * *

* S* .** * 6 The present invention relates to the realization that most wells do not flow from a single reservoir or location. The producing interval may in fact be several hundred meters in length and the production potential from the well is the integral of the production potential along its length. Further, it is appreciated that every position in the vell has a different production potential, largely as result of the varying permeability along the producing interval.

The present invention proposes the use of temperature and flow profile data to obtain a profile of the P1 along the length of the weilbore, which advantageously allows for an understanding of how the P1 varies by length and in time. It is highly likely that the P1 will vary by along the length of the welibore based on the two factors that determine the P1, namely permeability and skin. Permeability will vary by nature of the heterogeneous rock properties. Skin varies because of wellhore damage. This is where the time domain nature of a permanently installed Distributed Temperature Measurement finds particular use. The only factor that would result in permeability changing over time is a change in relative permeability and because of a change in the produced fluid (most likely a phase change). Changes in the fluid properties would be quickly and readily determined from surface measurement. Skin, on the other hand, can be altered by a number of factors.

Having a time domain measurement such as that employed within the present invention allows for the association of changes in the P1 profile due to permeability change and changes due to change in skin.

The P1 profile as now available according to the present invention will therefore find ready use within the petroleum engineer.

:.: The principle is explained by Fig. I which illustrates rock strata formation 10 offering separate reservoirs 12, 14 separated by an impermeable shale barrier 16. Here a wellbore temperature measuring device 18 is shown extending down a wellbore 20 through the *.

* S S*.

* strata 10. The welibore temperature measurement is used to determine a flow profile 22.

* Looking closely at the flow profile shows that each of the strata 10 bisected by the S... * S S S. *

*5.... S* 7

wellbore 20, provides a different flow contribution to the total flow from the well. In the example, and as mentioned, the welibore intersects two different reservoirs physically separated by the impermeable shale barrier 16. The reservoir pressure profile is shown as line 24. As there is pressure communication between the strata forming reservoir 12 the reservoir pressure is the same here. Likewise the pressure communication between the strata forming reservoir 14 dictates that these strata are at the same pressure. However, the shale barrier means the pressure differs between reservoir 12 and reservoir 14. The P1 profile determined in accordance with an aspect of the invention along the length of the wellbore 20 is shown as line 26.

Although the reservoir pressures can be measured before placing the well into productioii, the layer pressui-es cannot be easily measured during production. Knowing the respective reservoir 12, 14 pressures as a function of time is of great importance to ti-ic operating company as the rate of pressure depletion provides an indication of the oil in the reservoir and so enable the operating company to determine the production life for the well. Large pressure differentials can also result in lost production as hydrocarbons pass froni high pressure layer to a low pressure layer, rather than flowing along the weilbore to the surface.

To determine the initial value of the P1 profile the temperature measured by measuring device 18 needs to be inverted into the flow profile 22 along the length of the producing section. In a vertical oil well this is possible by analysing the cooling effects caused by the inflows and computing the flow from the amount of cooling, using techniques described in the paper by Curtis and Witteriholt.

Usually the initial reservoir pressures in the reservoir are known either through : measurement or simulation. Tools such as formation dynamic testers are often mn by *.S.

operating companies to determine the initial reservoir pressures. Likewise the weilbore flowing pressure can be determined from wellhead and bottom-hole pressure *...

measurements and modelled data. Since the initial reservoir pressures are therefore known, and the flow profile is obtained from the temperature profile, a P1 can be **.. S * *

S

S..... S 8

calculated at every position along the wellbore using the following simple relationship between the pressures and flow: Pt n -(p -Where: P[ Productivity Index at position n in the weilbore Q, Flow rate fron-i location n in the welibore Pen Reservoir pressure at position n along the welibore p Weilbore pressure at position n along the welibore At the heart of an aspect of the invention therefore is a calculation of multiple values for the P1 along the entire length of the weilbore, thereby creating a profile 26 of the P1 Although the exact magnitude of the measured interval is not particularly relevant, a convenient interval would be every 1 ft (--30 cm) along the welibore, as this is the interval iliost often used for wreline logs. Although Fig. I shows the producing layers or strata as fairly discrete elements it is likely that they are in fact constantly varying rather than being in discrete layers (especially in sandstone reservoirs). Therefore a short spacing for the P1 profile measurements would prove advantageous.

Providing distributed P1 means that the pressures in the reservoirs 12, 14 can be modelled as a bulk value, since physics dictate that in connected layers the pressure will naturally equalise and pressure should in fact be a bulk distribution, not discretely variable. 0* * .

This also means reservoir engineers will, by monitoring the temperature and flow profile over a period of time, be able advantageously to predict if reservoir pressures are *. indeed equal and connected, or isolated. *.S. *

** S* S. * . *S.. * S* S.

S

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Further, and according to another aspect of the present invention, and assuming that the P1 remains fixed over time (as it should do except in the condition mentioned previously) evaluation of the above mentioned equation shows how it proves possible to monitor the reservoir pressure, Pe, and determine any decline over a period of time. If we determine that the flow rate Q, at a particular position in the weilbore, is decreasing over time, we know that decline is due to a decrease in the reservoir pressure. By creating a concept of a Pt profile, the reservoir pressure can be easily described as a derivative of the flow profile. Change in the flow profile, derived from the change in temperature profile, is in turn associated with a reservoir pressure change. The reservoir pressure is calculated from: Pe p1 ±-If a well is under performing, stimulation is normally performed on the well to reduce the skin. The stimulation normally involves injecting an acid or a fluid ppt into the vell at high pressure in order to restore the permeability. The result is normally an increased flow rate for the same pressure drawdown, which can be measured as an improvement in the well Productivity Index.

Should well stimulation be performed, it would therefore result in a change in the P1 profile. The resultant change in the P1 profile can be advantageously employed within petroleum engineering since the effectiveness of the treatment along the length of the well can be determined. However, this change also has to be taken into account to ensure we correct calculation of reservoir pressure after the stimulation.

As the stimulation has no effect on the reservoir pressure, the last determined value of the reservoir pressure can be used and the above equation employed to determine the new value for the P1 after the stimulation. * S *SS.

*S S... * * *S.. * S. *

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*S5,** The process of monitoring the change in reservoir pressure and occasional change in P1 is illustrated in the flow chart of Fig. 2.

At 28, the initial reservoir pressure is measured and which leads, at step 30 to measurement of the flow profile for the well.

Next, the distributed productivity index is calculated at step 32 so as to arrive at a productivity index profile which, in turn, can provide, at step 34, for the related flow profile.

The reservoir pressures are then calculated at step 36 from the flow profile and, assuming normal operation as indicated at step 38, the procedure returns to step 34 for further measurenlent of the flow profile. However, if, subsequent to calculation of the reservoir pressures at step 36, it is determined that some form of well stimulation has occurred as illustrated by step 40, the flow rate from the well is measured at step 42 prior to the procedure returning to step 32 at which the distributed productivity index is again calculated. *5 * . * S.. S... * S *.I. *5*. * . *...

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S. 55.* * . *5* * SS S. *

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Claims

C Ia i nis A method of providing productivity index data for a

producing or injection well, wherein the said data is provided as a productivity index profile over a length of the well.
2. A method as claimed in Claim 1, wherein the productivity index profile is obtained through the calculation of niultiple values of the productivity index along the said length of the well.
3. A method as claimed in Claim 2, wherein the multiple values of the productivity index are calculated in the order of every 30cm along the said length of the well.
4. A method as claimed in Claim 1, 2 or 3, wherein the productivity index profile is derived from temperature profile data for the well.
5. A method as claimed in Claim 4, wherein the temperature profile data is obtained for the production, and/or the injection, interval.
6. A method as claimed in Claim 4 or 5, wherein the temperature profile is obtained by means of a distributed temperature measurement.
7. A method as claimed in any one or more of Claims 1 to 6 and including the step ol obtaining flow profile data from the said temperature profile data, and from which the productivity index profile is determined.

:..::.
8. A method as claimed in Claim 7, wherein the productivity index profile is obtained from: (*) * * *sI. ri = * (Pen -P) **Ss** * * **s* * S * S. 5

S S 12

Where, P11 Productivity Index at position n in the weilbore Q Flow rate from location n in the weilbore Pen Reservoir pressure at position n along the wellbore p Wellbore pressure at position n along the welibore
9. A method of managing oil well production including the above-mentioned method of determining productivity index data.
10. A method as claimed in Claim 9 and including the step of stimulating oil production, while monitoring any changes to the productivity index profile.
11. A computer program element containing instructions which, when loaded on a computer serve to control the computer to perform a method of providing profile index data claimed in any one or more of Claims I to 8.
1 2. A computer readable medium including a computer program element.
13. A computer hardware device arranged to operate in accordance with a computer program element as claimed in Claim 11.
14. A method of monitoring change in a reservoir pressure profile within a producing or injection well, and including the step of monitoring the change in welibore temperature profile over a period of time.
15. A method as claimed in Claim 14, wherein the change in welibore temperature profile is converted into a flow profile from which changes in the reservoir pressure profile can be identified. **.. * S **S.
16. A method of providing productivity index data for a producing or injection well and substantially as hereinbefore described with reference to the accompanying drawings. *S.* * I S S. *

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S..... S 13

1 7. A method of monitoring change in a reservoir pressure profile for a producing or injection well and substantially as hereinbefore described with reference to Fig. 2 of the accompanying drawings. * S * *** * * S... 5*I0 * . S. .5

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