NO328485B1 - Device and method for estimating relative permeability in a formation by NMR, resistivity and formation testing - Google Patents

Description

This patent application is related to and claims priority from US patent application serial number 09/910,209, entitled "Apparatus and Method for In Situ Analysis of Formation Fluids", of Krueger et al. filed July 20, 2001, which is hereby incorporated in its entirety by this reference. This application is related to and claims priority from US patent application serial number 60/369,268, entitled "NMR Measurements in a Pressure Gradient of a Formation Tester" belonging to Georgi et al, which is hereby incorporated in its entirety by this reference.

The present invention relates generally to the field of formation testing over time during or after drilling, and in particular to the simultaneous or sequential acquisition of nuclear magnetic resonance (NMR) data or resistivity data during formation testing to measure the saturation of the formation over time to determine the relative permeability of a hydrocarbon holding formation.

To obtain hydrocarbons such as oil and gas, wells are drilled by rotating a drill bit attached to the end of a drill string. A large part of the current drilling activity involves directional drilling, i.e. drilling of deviation boreholes and horizontal boreholes to increase hydrocarbon production and/or to extract additional hydrocarbons from the earth's formations. Modern directional drilling systems generally employ a drill string that has a bottom-hole assembly (BHA) and a drill bit at one end thereof, which is rotated by a drilling motor (mud motor) and/or by rotating the drill string. A number of downhole devices located in close proximity to the drill bit measure certain downhole operational parameters associated with the drill string. Such devices typically include sensors to measure downhole temperature and pressure, azimuth and inclination measuring devices, and a resistivity measuring device to determine the presence of hydrocarbons and water. In addition, downhole instruments, known as logging-while-drilling (LWD) tools, are often attached to the drill string to determine formation geology and formation fluid conditions during drilling operations.

Drilling fluid (commonly known as "mud" or "drilling mud") is pumped into the drill pipe to rotate the drill motor, provide lubrication to various elements of the drill string including the drill bit, and to remove cuttings produced by the drill bit. The drill pipe is rotated by means of a driving force, such as a motor, to facilitate directional drilling and to drill vertical boreholes. The drill bit is typically connected to a bearing assembly that has a drive shaft, which in turn rotates the drill bit attached to it. Radial bearings and thrust bearings in the bearing assembly provide support for the radial and axial forces on the drill bit.

Boreholes are usually drilled along predetermined paths, and the drilling of a typical borehole progresses through various formations. The drill operator typically controls surface-controlled drilling parameters, such as weight of the drill bit, flow of drilling fluid through the drill pipe, the rotational speed of the drill string, and the density and viscosity of the drilling fluid, to optimize drilling operations. Downhole operating conditions are constantly changing, and the operator must react to such changes and adjust the surface-controlled parameters to optimize drilling operations. For drilling a borehole in a new area, the operator typically has seismic survey plots that provide a macro picture of the formations in the subsurface and a borehole path planned in advance. For drilling several boreholes in the same formation, the operator also has information about previously drilled boreholes in the same formation.

The information provided to the operator during drilling typically includes borehole pressure and temperature and drilling parameters, such as weight-on-bit (WOB), rotation speed of the bit and/or drill string, and the flow rate of the drilling fluid. In some cases, the drill operator also receives selected information about the state of the bottom hole assembly (parameters), such as torque, the differential pressure of the mud motor, the jumping and swirling of the drill bit, etc.

Data from downhole sensors is typically to a certain extent processed downhole and transmitted using telemetry uphole by sending a signal through the drill string, or using mudhole telemetry which transmits pressure pulses through the circulating drilling fluid. Although mud pulse telemetry is more commonly used, such a system is capable of transmitting only a few (1-4) bits of information per second. Because of such a low transfer rate, the trend in the industry is worth the effort to process larger amounts of data downhole and transmit selected calculated results or "answers" uphole for use by the driller to control the drilling operations.

Commercial development of hydrocarbon fields requires significant amounts of capital. Before field development begins, operators want to have as much data as possible to evaluate the reservoir for commercial viability. Despite advances in downhole data collection using MWD systems, it is often necessary to perform additional testing of the hydrocarbon reservoirs to obtain additional data. Therefore, after the well has been drilled, the hydrocarbon zones are often tested with other test equipment.

One type of test performed after drilling involves producing fluid from the reservoir, shutting in the well, collecting samples with a probe or dual packings, reducing the pressure in a test volume, and allowing the pressure to build up to static levels. This sequence can be repeated several times at several different depths or points within a single reservoir and/or at several different reservoirs within a given borehole. One of the important aspects of the data that is collected during such a test is pressure build-up information that is collected after the pressure has been drained. From this data, information can be derived with regard to permeability and size of the reservoir. Furthermore, actual samples of the reservoir fluid must be obtained, and these samples must be tested to collect pressure-volume-temperature and fluid properties such as density, viscosity and composition.

A more recent system is described in US patent no. 5,803,186 belonging to Berget et al ('186 patent). The '186 patent provides an MWD system that includes the use of pressure and resistivity sensors in conjunction with the MWD system to allow real-time data transmission of these measurements. The '186 device makes it possible to provide static pressures, pressure buildups, and pressure drawdowns with the work string, such as a drill string, in place. Furthermore, calculation of permeability and other reservoir parameters based on the pressure measurements can be carried out without pulling the drill string.

The system described in the '186 patent reduces the time required to perform a test compared to using a cable. However, the '186 patent does not provide a means for improved efficiency when cable applications are desired. A pressure gradient test is such a test where several pressure tests are taken when a cable leads a test device down through a borehole. The purpose of the test is to determine the fluid density on site and to determine the interface or contact points between gas, oil and water when these fluids are present in a single reservoir. Another apparatus and method for measuring formation pressure is described in US patent no. 5,233,866, issued to Robert Desbrandes.

Various means of estimating permeability from Darcy's law that have been proposed for formation testing are well known in the art. For example, US Patent No. 5,303,775 to Michaels describes a reservoir characterization instrument that enables an operator to determine formation properties from formation test measurements of pressure, volume and temperature performed in situ downhole in the wellbore. It is well known that determinations of absolute formation permeability and fluid mobility can be derived from measurements of pressure, volume, temperature and viscosity. Permeability is useful in determining the potential productivity of a formation with a wellbore. It is also known that downhole NMR tools also enable an operator to determine formation parameters of interest, including permeability from NMR measurements entered in situ. These methods generally do not distinguish between absolute, effective and relative permeability.

However, these known methods for determining surrounding formation permeability do not take into account the saturation level in the surrounding formation or determining the relative permeability of the formation. The absolute permeability represents the permeability of a fluid when there is only a single fluid in the formation. Since most formations contain more than one fluid, it is more relevant to determine the permeability of one fluid in the presence of another fluid at a given saturation level, i.e. the relative permeability. It is the relative permeability that determines the actual productivity of a formation surrounding a well. There is thus a need for a method and a device for determining the saturation level of the surrounding formation and the relative permeability of the surrounding formation.

The present invention analyzes a formation at a wellbore.

Formation testing, resistivity measurement and NMR are performed simultaneously to determine a relative permeability representative of the formation surrounding the borehole. The present invention provides a method and apparatus for accurately determining the relative permeability of a formation by measuring the saturation level in an area of interest determined from readings of NMR or resistivity versus time during pressure drawdown testing of the formation. The present invention determines effective permeability over time for different saturation levels to determine the relative permeability of the formation at each saturation level. In another aspect, the present invention also enables determination of the effect of using completion fluids in the formation to increase formation productivity. In another aspect, the present invention enables more accurate determination of effective permeability. In another aspect of the invention, the present invention enables determination of the irreducible saturation level. In another aspect of the invention, the present invention enables determination of the effect of using completion fluids in a formation. In another aspect of the invention, there is provided a method and apparatus for determining whether a sidewall pad is properly sealed against a borehole wall.

In another aspect of the invention, there is provided a method and apparatus for determining whether a fluid passage for pumping fluid from the formation is plugged. Other features and advantages will clearly appear from the following description.

Brief description of the drawings:

Fig. 1 is an illustration of a preferred embodiment of the present invention applied in a borehole in an operation with monitoring while drilling to determine the relative permeability of the formation surrounding the borehole; Fig. 2 is an illustration of a tool for measuring saturation level mounted on a sidewall pad, comprising an NMR or resistivity device and a formation test probe used in a wellbore to perform resistivity, NMR and formation testing in a preferred embodiment of the present invention for determining the relative permeability of the formation surrounding the borehole; Fig. 3 is an illustration of an alternative embodiment of the present invention, comprising a dual packing tool combined with a formation testing tool, resistivity and NMR measuring tool for determining the relative permeability of the formation surrounding the borehole; and Fig. 4 is an illustration of a water-oil relative permeability curve for water/oil saturation levels varying between 0 and 100%, showing the relative permeability as a percentage of absolute permeability achievable for water and oil at a continuum of water/oil saturation levels.

The present invention enables simultaneous or simultaneous NMR saturation measurements and formation test measurements to determine the relative permeability of a formation, which is of significant benefit to oil field analysts attempting to determine the productivity of a well. Fig. 1 shows a preferred embodiment of the present invention used in a bottom hole assembly.

Reference should now be made to fig. 1. Fig. 1 shows a drilling device according to an embodiment of the present invention. A typical drilling rig 202 with a borehole 204 extending therefrom is shown, which is well understood by those skilled in the art. The drilling rig 202 has a working string 206, which in the embodiment shown is a drill string. A drill bit 208 is attached to the drill string 206 for drilling the drill hole 204. The present invention is also useful with other types of work strings, and is useful together with a cable, a jointed pipe, coiled pipe or other small diameter work strings, such as snubbing pipes. the drilling rig 202 is shown positioned on a drilling ship 222 with a riser 224 extending from the drilling ship 222 to the seabed 220. However, any drilling rig configuration such as a land-based rig can be adapted to implement the present invention.

If applicable, the drill string 206 may have a downhole drilling motor 210. In the drill string 206 above the drill bit 208, a typical test unit is incorporated, which may have at least one sensor 214 to sense the downhole characteristics of the drill hole, the drill bit and the reservoir, such sensors are well known in the field. A useful application of the sensor 214 is to determine the direction, azimuth and orientation of the drill string 206 using an accelerometer or similar sensor. The BHA also contains the formation test device 216 according to the present invention, which will be described in more detail below. A telemetry system 212 is located in a suitable location on the work string 206, such as above the test device 216. The telemetry system 212 is used for commands and data communication between the surface and the test device 216.

In a preferred embodiment, to determine relative permeability or mobility, the present invention quantifies fluid saturations in the pore space with NMR or resistivity when the reservoir pressure and effective permeability and mobility are determined. Mobility is equal to the permeability divided by the viscosity. There are several methods for determining viscosity from NMR data, as described in US patent no. 6,084,408 belonging to Georgi, et al. One can determine intrinsic T2 and determine viscosity from a correlation as described by Vinejar et al, where T2 is proportional to absolute temperature/viscosity. One can also use NMR to determine viscosity using Einstein's relationship, as V is proportional to absolute temperature/diffusivity. NMR determines viscosity, which is used to convert mobility to permeability.

The saturation level in front of the probe changes when the fluid is pumped from the formation. These steps are repeated until the mobile fluid saturation and the effective permeability have been determined at each saturation level. The result is a series of determinations of effective permeability and mobile fluid saturation at varying saturation levels. The process is stopped when the water saturation level no longer falls. At this level, the irreducible fluid saturation has been reached.

Fig. 4 is an illustration of the relative permeability for water 410 and for oil 420 at given saturations of water and oil. The relative permeability is shown as a fraction of Keffective/Kabsoiutt, where Keffective is approximately equal to Kabsoiutt for water when the water saturation 422 approaches 100%, and Keffective is approximately equal to Kabsoiutt for oil when the oil saturation approaches 100%. As shown in fig. 4, the relative permeability for oil, Kr, varies from approximately Kabsoiutt to approximately 0 when the water saturation increases from approximately 0 to 100. Correspondingly, the relative permeability for water, K™, varies from approximately Kabsoiutt to approximately 0 when the oil saturation increases from approximately 0 to 100%

Standard formation testing is well known in the art. However, pressure testing cannot measure flow rate in the formation. Such tests are limited to measuring fluid flow entering the pressure test tool. The present invention determines fluid velocity in or near the NMR or resistivity sensitive volume, and combines this information with the estimated pressure gradient across the NMR/resistivity sensitive volume to determine permeability in the sensitive volume.

NMR can be used to determine the velocity of a fluid in a similar way to diffusion measurement, where the magnetic spins are moved irregularly within the formation from a position in the field gradient, which changes the Larmor frequency of the spins, to detect the motion of the spins. Such known NMR techniques are used, for example, to detect blood flow in the human body. The NMR determination of fluid velocity is used to correct the fluid velocity derived from pressure tests.

Additional sensors are arranged in the test device 216 along with measuring devices for NMR and formation testing, and the measurements include resistivity, near infrared refractometry, viscosity sensors, dielectric sensors and optical spectroscopy. These additional sensors are well known in the art and for the sake of simplicity are not shown in detail in the figures. A processor is arranged in the tool downhole for calculation, correlation and correction of the various test parameters and measurements. A neural network trained from a test base of correlated formation properties is arranged to infer an unknown formation property from other known, measured or estimated formation properties.

The present invention uses the determination of the fluid velocity of the pore space to derive a value for the permeability which is more accurate than the permeability determined by NMR. NMR permeabilities are based on the surface area of the pore space and the distribution of the pore space. NMR alone cannot determine tortuosity, i.e. how the pore space is connected. A multiple inter-echo time, Te, or a multiple waiting time, Tw, NMR experiment provided by the present invention distinguishes between a low-viscosity and a high-viscosity fluid in the pore space, for example water as opposed to oil, or heavy oil and light oil , and distinguish between fluids or phases, for example water, oil, gas, by means of an NMR experiment that uses multiple relaxation times, Ti. The present invention also determines whether formation fluid or wellbore fluid is taken into the tool during drawdown testing.

The present invention enables the determination of relative permeability. Relative permeability characteristics are important for understanding the movement of hydrocarbons at any stage of production. Darcy's law as originally developed applies to a porous medium, which is completely saturated with a single-phase fluid. In the typical reservoir, however, there are usually two or more fluids, so that it is necessary to introduce the concept of effective permeability. In the definition of effective permeability, each fluid phase is considered to be completely independent of the other fluids. Darcy's law can thus be applied to each fluid individually. The absolute or specific permeability is the permeability with only one fluid present at 100% saturation of the pore space. The effective permeability is the permeability of a fluid phase in the presence of another fluid phase. The effective permeability is the conductivity of each phase at a specific saturation of the other phase.

In addition to being affected by the saturation of the other fluids, effective permeability is also a function of the rock's wetting characteristics and pore geometry. Relative permeability is defined as the ratio between the effective permeability of a fluid at a given saturation and the specific permeability of this fluid at 100% saturation.

The relative permeability ratio is reported as a fraction or percentage. In tests of relative permeability, an effective permeability is often used as a base permeability. Instead of always using the permeability when only one fluid is present at 100% saturation as the base value, the permeability of a fluid is often used when the other fluid is immobile, for example the permeability of oil at non-reducible water saturation UKo @ Swir). It is important to ensure that a common basis is used when evaluating or comparing data.

Relative permeability is affected by the distribution of fluids in the rock, the saturation history and the degree of wetting of the rock. The saturation history affects the data, and therefore tests must follow the reservoir history. The degree of wetting of the rock affects the fluid distribution and therefore the flow inside the reservoir. Samples with non-representative degree of wetting will give non-representative data.

Absorption relative permeability describes the characteristics of the relative permeability when the wetting phase increases, for example in the case of water flooding in a reservoir that is wet due to water. Drainage relative permeability describes characteristics of the relative permeability when a non-wetting phase increases, for example when gas displaces oil during primary recovery, or oil displaces water during initial oil migration into a reservoir. Indications of relative permeability characteristics in the distribution of fluid within porous media can be derived from relative permeability data. When non-wetting oil migrates into the water-filled reservoir, it first displaces water from the larger pores. This displacement results in a rapid drop in the water's relative permeability.

As the oil saturation continues to increase, the remaining water occupies successively smaller pores, which is characterized by a rapid increase in the oil's relative permeability.

Secondary imbibition of water during waterflooding results in a different set of relative permeability curves. Assuming a water-wet situation, oil occupies the center of the large pores, and water exists as a thin film around the grains, occupying only the smallest pores that were not originally invaded by oil. At this stage the water is immobile and has little or no effect on the flow of oil, and the relative permeability to the oil is at this stage 100%. The water saturation before the water flooding is immobile, and the water's relative permeability is zero. Water flow none results in the water initially flowing through the large pores and then through smaller pores as the oil saturation decreases. The water saturation continues to increase as the oil saturation decreases to a residual saturation. At this stage, the remaining oil remains trapped in the center of the pores. As the oil is no longer mobile, the relative permeability of the oil becomes zero, while the relative permeability of the water reaches its maximum. This value will not reach 100%, which is due to the remaining oil saturation which limits the flow, so that the permeability of the water at this stage is an effective permeability.

In an oil-wet reservoir, oil clings to the surfaces of the grains, and water exists as trapped droplets in the center of the pores or in the smallest pores that were not invaded by oil during the initial oil migration into the reservoir. In this situation, the oil's relative permeability will be lower, as the flow of oil will be hindered by the oil-wet nature of the rock retaining the oil. Conversely, the relative permeability to water will be higher than in a water-wet situation.

Reference should now be made to fig. 2, where the present invention provides a device for determining saturation that can be mounted on a sidewall pad, for example an NMR or resistivity device and a formation testing tool that is mounted in an extendable probe, and a sidewall pad device on either a logging-while-drilling tool or a cable-formation-tester-probe assembly such as the Baker Atlas Reservoir Characterization Instrument (RCI). RCI is detailed in US patent no. 5,303,775 belonging to Michaels et al, which is hereby incorporated in its entirety by this reference. An extendable probe assembly on a formation tester for monitoring during drilling is detailed in US Patent Application No. 09/910,209 discussed above. In either configuration, cable or logging while drilling, the present invention provides for the determination of relative permeability over time derived from formation and pressure drawdown testing over time, combined with NMR or resistivity saturation measurements over time to determine relative permeability. As shown in fig. 2, in a preferred embodiment, the resistivity/NMR saturation measurement is limited to an area associated with a localized resistivity/NMR region of interest 316 close to the borehole 332, within a few radii of the formation test tool probe, i.e. the radius of the internal passage or opening provided for the entry of formation fluid 330 and exit of completion fluid through the borehole wall 314, to the formation. The probe 310 extends from the downhole tool to press and seal the probe face 319 against the wellbore wall 314. Formation fluid is withdrawn from the wellbore through the probe 310. Completion fluid is injected into the formation through the probe 310. The provision of adjacent formation testing and NMR equipment in the same downhole facility. -the tool enables the simultaneous determination of saturation level and absolute permeability with NMR (Coates-Timur equation) data and mobility data from drawdown build-up analysis performed using the formation testing equipment.

The present invention also provides a method and apparatus for determining absolute "end-point" permeability of either oil or water when the area is surveyed, i.e. that the area within approx. 3 probe radii of the inner probe opening are either 100% water- or oil-saturated, for example 100% water-based sludge filtrate. The present invention also determines the relative permeability to oil for a plurality of water saturation levels. Having both formation testing and NMR-measured permeabilities enables comparison of the measurements and improvement of the parameters in the Coates-Timur equation or the NMR permeability which is based on the T2 geometric mean, based on calculated permeability from the formation testing. However, the primary advantage of the present invention is the ability to determine the relative permeability of the formation based on the calculation of saturation levels over time from NMR measurements or resistivity measurements and calculations of effective permeability over time to determine the relative permeability of the formation at given saturation levels.

Critical gas and condensate saturations, residual oil saturation, saturations of trapped oil and gas, and non-reducible water saturation are the endpoints that are most often encountered. Critical saturation, whether for gas or condensate, refers to the saturation at which a phase first becomes mobile. Trapped gas, residual oil, and irreducible water saturations all refer to the remaining saturation of a phase after extensive displacement has occurred.

This investigation is consistent with the interpretation that the "end point" saturations refer to the saturations in a rock with two phases, where one phase becomes immobile. For example, as the water saturation increases, oil will eventually no longer flow, and the remaining oil saturation (Sro) when the oil is no longer flowing and only water is flowing, will be the "endpoint" oil saturation. On the other hand, when the water saturation becomes small and approaches the irreducible water saturation, the water will stop flowing and we will be at the irreducible "end point" of the water saturation.

Fig. 3 illustrates an alternative embodiment of the present invention where a dual packing tool is used combined with a formation testing and an NMR measurement tool for determining the relative permeability in the formation surrounding the borehole. Reference should now be made to fig. 3, where a dual packing-formation test tool combined with an NMR sensor is shown. A multi-sensor device package 312 that includes a resistivity measuring device is located inside the tool. An intelligent gathering and completion system 313 is located on the surface for receiving input from the tool and processing the input to make determinations about further gathering and actions in the borehole or formation. A set of hydraulic seals 307 and 306 engage the borehole wall and seal off an area of the annulus through which formation fluid can enter the tool. The suction line 310 in the formation tester enables formation fluid or wellbore fluid to enter the tool. A zone of interest 304 is set up by the NMR permanent magnets 301 and 305 and the NMR RF antenna 303. A hydraulic line 308 in packing 1 and hydraulic line 311 in packing 2 actuate the packings to seal off a region of the inter-packing annulus 1 and packing 2.

In a preferred embodiment, fluid velocities and saturation levels are determined directly with the resistivity tool in the multisensor package 312 or the NMR probe in the NMR sensitive volume using an NMR measurement technique combined with estimates of the pressure gradient across the NMR sensitive volume to determine a relative permeability for a given saturation level in the sensitive volume. The pressure gradient calculation uses absolute permeability derived from mobility data from the formation quantity analysis which converts the formation test based mobility to permeability. This is accomplished by using NMR data or resistivity saturation data, as discussed below.

The collection and processing of NMR data for the calculation of a parameter of interest for a formation is well known in the art. In a preferred embodiment, NMR parameters are obtained, T1 and T2 with dual or multiple TE and/or dual or multiple TW NMR data and/or diffusion data are used to determine viscosity and transform the formation test determined mobility into a determination of relative permeability. In a preferred embodiment, the relative permeability (k) or mobility (k/n) (n=viscosity) is calculated by determining a saturation value for a location in a formation; measuring a pressure value for the location in the formation; and determining the relative permeability of the formation from the saturation value and the pressure value at the location in the formation. In a preferred embodiment, NMR or resistivity measurements are used to monitor saturation of the wetting phase, i.e. water in the formation, which measures the pressure in the formation as different saturations. The NMR measurements also provide viscosity.

The NMR or resistivity measurements are performed during the same downhole run or in a separate downhole run, such as the pressure testing run. The NMR measurements enable the estimation of saturation levels in the formation and help determine relative permeability. In an alternative embodiment, resistivity measurements are used to provide an estimate of saturation levels in the formation location being pressure tested. Resistivity or dielectric agents are used to estimate formation saturation.

In a preferred embodiment, the fluid saturation levels in the NMR region of interest in the formation's pore space are determined using NMR, and at the same time the formation mobility is determined from formation or reservoir pressure testing using analytical methods as described in US patent application serial number 09/910,209 filed July 20, 2001, entitled "Apparatus and Method for In Situ Analysis of Formation Fluids", belonging to Krueger et al.

As formation fluid is pumped from the formation during pressure testing, water that had invaded the formation is pumped from the formation, reducing the water's saturation level. Correspondingly, the oil's saturation level increases over time as pumping continues. Thus, over time, the water saturation level in front of the probe changes as the water is emptied. The water's falling saturation level is monitored with NMR while water is pumped from the formation as the water and oil saturation changes over time.

In a preferred embodiment, the present invention injects a fluid having a known viscosity into the formation, and uses NMR or resistivity measurements to determine saturation levels in the formation, measures pressure responses, injects more fluid into the formation to change the saturation level in the formation, uses NMR or resistivity to determine saturation levels in the formation, and from this determine relative permeability or mobility.

The determination of the mobility is repeated over time using the drawdown build-up determination with the formation test tool. These steps are repeated until one has determined the mobile fluid saturation level and the effective permeability at each NMR or resistivity measured saturation level. The process is complete when the water saturation does not decrease further, or after a reasonable period of time has elapsed, so that the "true" non-reducible fluid saturation level is reached. The irreducible fluid saturation level is the water saturation level that will not decrease with further pumping from the formation. The irreducible water saturation level is important in determining the productivity of a formation. The non-reducible water saturation level can be improved by injecting completion fluid, as discussed below.

These saturation data and effective mobility data combined with time enable the plotting of a curve of relative permeability, as shown in fig. 4, from the calculated data points. If the drilling mud is water-based, this process will produce Kro, the relative permeability of oil at different water saturation levels when drilling mud is pumped to or from the formation. In a preferred embodiment, where a drawdown build-up test is performed at the same time as the fluid saturations as observed by NMR or resistivity have stabilized, an "end-point" relative permeability is calculated.

The effect of using completion fluid in the formation is determined by means of the present invention. In a preferred embodiment, completion fluid is pumped into the formation until maximum saturation is achieved. By pumping completion fluid back out of the formation, the present invention can monitor changes in degree of wetting using NMR data to estimate the potential impact of using completion fluid to increase production in the well. For example, if a lower non-reducible fluid saturation level is reached after injection and withdrawal of completion fluid, this indicates that the formation is likely to benefit from the use of completion fluid. The present invention also injects fluid having known NMR or resistivity properties into the formation to be used as a tracer to track movement of the injected fluid.

The present invention also determines the degree of wetting in the formation, i.e. the formation's affinity for oil or water. Completion fluids containing fluids that change the degree of wetting (to make the formation wet with water) are pumped into the formation, and then pumped out using a combination of drawdown testing and NMR testing to determine whether the non-reducible saturation is lower after injection and removal of replenishment fluid than the irreducible saturation level before injection of replenishment fluid.

The present invention also determines the integrity of the seal between the wellbore wall and the tool's probe sidewall pad. In a typical cable environment, the wellbore accumulates a mud cake on the wall of the wellbore with a thickness of 1-3 mm. This mud cake can prevent or inhibit sealing of the extendable probe and the sidewall pad against the wellbore wall. The present invention determines the NMR fluid velocity and compares it to the fluid velocity based on the theoretical model of the formation for the drawdown rate being used. If the measured and theoretical speeds correspond to each other, this indicates a good probe seal. If the measured speed is less than the theoretical speed, then this shows a leak in the probe seal. The present invention also shows when the probe is plugged during drawdown testing by immediately detecting when there is no flow rate in the formation even though there may be a pressure build-up in the tool.

NMR data is taken with and without the pressure gradient in the region of interest to determine which fluid is mobile and which fluid is not. The NMR experimental parameters are chosen to trace only the non-reducible fluid, i.e. the fluid that remains in place for a relatively long period of time, i.e. 500 sec. The present invention also injects fluids mixed with hyperpolarized elements such as xenon gas, argon gas or helium gas or any other NMR traceable element. These hyperpolarized elements increase the NMR signal and response, increasing the signal-to-noise ratio of the NMR measurement. The present invention also provides data for an intelligent completion system. Data relating to whether fluids or solids are moving in the formation. For example, movement of sand in the formation, which is undesirable in a production situation, will be of particular interest for an intelligent, complete mining system.

Although a preferred embodiment of the present invention has been shown by way of illustration, this is for illustrative purposes only and is not intended to define or limit the scope defined by the following claims.

Claims (21)

1. A downhole tool, comprising: a probe (310) deployed down a wellbore at a surrounding formation; a pressure measuring device connected to the probe (310) for determining, in use, fluid mobility for a location in the formation; a device for measuring, in use, a saturation level for the localization in the formation comprising an NMR or a resistivity tool characterized by: a component of relative permeability for calculating, using the determined pressure and saturation level, a relative permeability value which is represented by the permeability value of the location at the saturation level of the location. 2. Downhole tool according to claim 1, where the device for measuring a saturation level comprises NMR tools. 3. Downhole tool according to claim 1, where the device for measuring a saturation level comprises a resistivity tool. 4. Downhole tool according to claim 1, further comprising: an injector for injecting fluid into the formation. 5. Downhole tool according to claim 1, further comprising: a processor for comparing the mobility from the formation test with the NMR permeability for adjusting the NMR parameters. 6. Method for determining relative permeability in a formation, comprising: injecting a fluid having a known viscosity into a formation location; determination of saturation level using an NMR or resistivity tool to determine saturation level in the formation location; measuring pressure responses in the formation; characterized by: injecting additional fluid into the formation to change the saturation level in the formation; determination of saturation levels in the formation using NMR or the resistivity tool; and determination of relative permeability using pressure and saturation levels. 7. Method according to claim 6 for determining relative permeability for a formation, comprising: determination of a saturation level at a location in the formation; measuring a pressure value for locating in the formation; and determination of the relative permeability of the formation from the saturation value and the pressure value at the location in the formation. 8. Method according to claim 6, further comprising: performing a nuclear magnetic resonance measurement at the location in the formation; determination of viscosity for the location in the formation from the NMR measurement; and calculation of permeability from the mobility. 9. Method according to claim 6 for calculating formation productivity, comprising: deploying an NMR and pressure measurement device in a borehole at a formation; measuring mobility for a location in the formation using pressure testing; measuring the saturation level of the localization using NMR; and calculation of permeability for the measured mobility and saturation at the formation location. 10. Method according to claim 9, further comprising: transformation of mobility into permeability using viscosity data. 11. The method of claim 9, further comprising: continuing to measure mobility and saturation to calculate permeability at different saturation values until the saturation value stops changing during pumping from the formation for pressure testing. 12. Method according to claim 11, further comprising: calculation of the irreducible saturation level. 13. Method according to claim 12, further comprising: injection of completion fluid into the formation; and calculation of the irreducible saturation level. 14. Method according to claim 12, further comprising: injection of completion fluid into the formation; and calculating a moving saturation level. 15. Method according to claim 9, further comprising: mixing a hyper-polarized agent in a fluid to increase the signal to noise ratio for NMR measurements; and injecting the fluid containing the hyper-polarized agent into the formation. 16. Method according to claim 9, further comprising: pumping fluid from the formation through a flow line; and monitoring the flow rate to determine when the flow line is blocked. 17. Method according to claim 9, further comprising: measuring the fluid flow in a probe (310); and comparing the measured fluid flow with a hypothetical fluid flow for the pressure gradient formed by the probe (310) to determine whether the probe (310) is sealed against the borehole wall (314). 18. Method according to claim 9, further comprising: provision of information to an intelligent completion system (313). 19. Method according to claim 9, further comprising: testing fluid in a probe (310) to determine whether the fluid is wellbore fluid or formation fluid. 20. Method according to claim 9, further comprising: determination of an endpoint permeability for at least one of oil and water. 21. Method according to claim 6, further comprising: measurement of resistivity for a location in the formation location; fluid saturation monitoring; and calculation of relative permeability.