METHOD TO CONTROL THE FLOW RATES OF FOCUS SAMPLING PROBE TO ENABLE FASTER CAPTURE OF CLEAN FORMATION FLUID

Description

BACKGROUND

During oil and gas exploration, many types of information may be collected and analyzed. The information may be used to determine the quantity and quality of hydrocarbons in a reservoir and to develop or modify strategies for hydrocarbon production. For instance, the information may be used for reservoir evaluation, flow assurance, reservoir stimulation, facility enhancement, production enhancement strategies, and reserve estimation. One technique for collecting relevant information involves pressure testing a reservoir of interest at any specified depth and reservoir fluid collection. There are a variety of different tools such as formation testing tools that may be used to perform downhole formation sampling and pressure measurements. Formation testing tools may be conveyed downhole in a variety of ways, including wireline and drill string. Formation testing tools determine the formation pore pressure, estimate the formation mobility (ratio of permeability over viscosity or k/μ), and can collect samples of reservoir fluids. The collected representative reservoir fluids are then sent to a surface laboratory to conduct PVT and compositional analysis. Therefore, it is important to obtain clean and representative reservoir fluid sample in a timely fashion as contaminated samples lead to inaccurate analysis results and erroneous reservoir assessments.

During the drilling process, a specialized drilling fluid, commonly referred to as “drilling mud,” is used to lubricate the drill bit, carry cuttings to the surface, and maintain wellbore stability. However, drilling mud is not a static component as it can inadvertently infiltrate the surrounding formation rock, leading to a phenomenon known as “drilling fluid filtrate invasion.” This invasion poses a significant challenge for formation testers seeking to obtain clean and representative reservoir fluid samples. Traditional methods of formation fluid sampling often involve using formation tester equipped with point probes and/or dual packers, depending upon the expected formation fluid mobility. In low formation fluid mobility, the formation testing tools may operate a long time (up to several hours) to obtain a representative reservoir fluid sample as it takes a long time to pump the drilling fluid filtrate out of the reservoir fluid and decrease its content in the extracted reservoir fluid. However, long waiting times with a stationary tool are undesirable in field operations as they increase both the rig time and the risk of differential tool sticking. Nevertheless, the information that formation testing tools can deliver is sufficiently valuable to operators that many are willing to wait, even hours, to obtain representative reservoir fluid sample with no or relatively low drilling fluid filtrate contamination.

To further reduce sampling time, the oil service industry may provide a type of point probe called focused probe pad, with inner and outer flowing areas separated by a rubber barrier. The outer flowing area serves as guarding probe that actively absorbs drilling fluid filtrate and prevents near wellbore drilling fluid filtrate from entering the inner flow area or clean probe, so that the drilling fluid filtrate content can be quickly reduced in the clean probe during the pump out stage, enabling faster clean up than the one obtained with conventional non-focused probe.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments of the present disclosure, and should not be used to limit or define the disclosure;

FIG. 1 is a schematic diagram of an example of a formation testing tool on a wireline;

FIG. 2 is a schematic diagram of an example of the formation testing tool on a drill string;

FIG. 3 is a schematic drawing of the formation testing tool;

FIG. 4 illustrates a focused sampling probe with a guard probe and a clean probe according to embodiments of the present disclosure;

FIG. 5 is a numerical simulation of the contamination level of reservoir fluid inside a flow line detected by a fluid analyzer as a function of time according to embodiments of the present disclosure;

FIG. 6 represents the simulation of the pressure as a function of the radial distance around the clean probe when the flow rate inside the guard probe is increased by 50% while the flow rate inside the clean probe is kept constant after 4 hours in FIG. 5; and

FIG. 7 represents the simulation of the pressure inside the clean probe versus the pressure inside the guard probe as a function of depth around the wellbore and radius when the flow rate inside the guard probe is increased by 50% while the flow rate inside the clean probe is kept constant after 4 hours in FIG. 5.

DETAILED DESCRIPTION

Disclosed herein are systems and methods to obtain representative reservoir fluid samples faster by strategically controlling the flow rates of the guard probe and clean probe to speed up cleaning of the reservoir fluid sample inside the flow line of the formation testing tool connected to the clean probe. More specifically, while the ratio of pumping flow rates of the guard probe and clean probe is held constant until reaching a pre-determined value of drilling fluid filtrate contamination such as around 10% for example, this ratio of pumping flow rates is then increased by at least 10% by increasing the pumping flow rate of the guard probe and/or by decreasing the pumping flow rate of the clean probe to reduce pressure inside the guard probe, to create a stronger guarding effect, and to pull dirty fluid including drilling fluid filtrate contamination away from the clean probe into the guard probe.

Contamination from drilling fluid filtrate may be differentiated from reservoir fluid using various measurement sensors including densitometer sensor, resistivity sensor, optical sensor, viscosity sensor, Nuclear Magnetic Resonance (NMR) sensor, acoustic sensor (measuring the speed of sound), for example. For example, densitometer sensors may be desired to differentiate drilling fluid filtrate from reservoir fluid due to their contrasting densities.

The increase of flow rate for the guard probe and/or the decrease of the flow rate of the clean probe depends upon the targeted increase of differential pressure between the guard probe and the clean probe. The added differential pressure speeds up the cleaning process of the reservoir fluid coming from the clean probe and enables faster sampling of clean reservoir fluids.

In embodiments, a system comprises a non-transitory computer readable medium having data stored therein representing a software executable by a computer. The software executable includes instructions configured to pumping reservoir fluid from the downhole formation from the guard probe to at least one flow line of the formation testing tool at a first flow rate, pumping reservoir fluid from the downhole formation from the clean probe to the second flow line at a second flow rate, wherein a ratio of flow rates between the first flow rate and the second flow rate is held constant until reaching a first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe, changing the ratio of flow rates between the first and second flow rates, and sampling a reservoir fluid when reaching a second pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

FIG. 1 is a schematic diagram of a formation testing tool 100 on a conveyance 102. As illustrated, wellbore 104 may extend through subterranean formation 106. In examples, reservoir fluid may be contaminated with well fluid (e.g., drilling fluid) from wellbore 104. As described herein, the fluid sample may be analyzed to determine fluid contamination and other fluid properties of the reservoir fluid. As illustrated, a wellbore 104 may extend through subterranean formation 106. While the wellbore 104 is shown extending generally vertically into the subterranean formation 106, the principles described herein are also applicable to wellbores that extend at an angle through the subterranean formation 106, such as horizontal and slanted wellbores. For example, although FIG. 1 shows a vertical or low inclination angle well, high inclination angle or horizontal placement of the well and equipment is also possible. It should further be noted that while FIG. 1 generally depicts a land-based operation, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

As illustrated, a hoist 108 may be used to run formation testing tool 100 into wellbore 104. Hoist 108 may be disposed on a vehicle 110. Hoist 108 may be used, for example, to raise and lower conveyance 102 in wellbore 104. While hoist 108 is shown on vehicle 110, it should be understood that conveyance 102 may alternatively be disposed from a hoist 108 that is installed at surface 112 instead of being located on vehicle 110. Formation testing tool 100 may be suspended in wellbore 104 on conveyance 102. Other conveyance types may be used for conveying formation testing tool 100 into wellbore 104, including coiled tubing and wired drill pipe, for example. Formation testing tool 100 may include a tool body 114, which may be elongated as shown on FIG. 1. Tool body 114 may be any suitable material, including without limitation titanium, stainless steel, alloys, plastic, combinations thereof, and the like. Formation testing tool 100 may further include one or more sensors 116 for measuring properties of the fluid sample, reservoir fluid, wellbore 104, subterranean formation 106, or the like. In examples, formation testing tool 100 may also include a fluid analysis module 118, which may be operable to process information regarding fluid sample, as described below. Formation testing tool 100 may be used to collect fluid samples from subterranean formation 106 and may obtain and separately store different fluid samples from subterranean formation 106.

In examples, fluid analysis module 118 may include at least one sensor that may continuously monitor a reservoir fluid. Such sensors include optical sensors, acoustic sensors, electromagnetic sensors, conductivity sensors, resistivity sensors, selective electrodes, density sensors, mass sensors, thermal sensors, chromatography sensors, viscosity sensors, bubble point sensors, fluid compressibility sensors, flow rate sensors. Sensors may measure a contrast between drilling fluid filtrate properties and formation fluid properties.

In examples, fluid analysis module 118 may be a gas chromatography analyzer (GC). A gas chromatography analyzer may separate and analyze compounds that may be vaporized without decomposition. Fluid samples from wellbore 104 may be injected into a GC column and vaporized. Different compounds may be separated due to their retention time difference in the vapor state. Analyses of the compounds may be displayed in GC chromatographs. In examples, a mixture of formation fluid and drilling fluid filtrate may be separated and analyzed to determine the properties within the formation fluid and drilling fluid filtrate.

Fluid analysis module 118 may be operable to derive properties and characterize the fluid sample. By way of example, fluid analysis module 118 may measure absorption, transmittance, or reflectance spectra and translate such measurements into component concentrations of the fluid sample, which may be lumped component concentrations, as described above. The fluid analysis module 118 may also measure gas-to-oil ratio, fluid composition, water cut, live fluid density, live fluid viscosity, formation pressure, and formation temperature. Fluid analysis module 118 may also be operable to determine fluid contamination of the fluid sample and may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, fluid analysis module 118 may include random access memory (RAM), one or more processing units, such as a central processing unit (CPU), or hardware or software control logic, ROM, and/or other types of nonvolatile memory.

Any suitable technique may be used for transmitting signals from the formation testing tool 100 to surface 112. As illustrated, a communication link 120 (which may be wired or wireless, for example) may be provided that may transmit data from formation testing tool 100 to an information handling system 122 at surface 112. Information handling system 122 may include a processing unit 124, a monitor 126, an input device 128 (e.g., keyboard, mouse, etc.), and/or computer media 130 (e.g., optical disks, magnetic disks) that can store code representative of the methods described herein. Information handling system 122 may act as a data acquisition system and possibly a data processing system that analyzes information from formation testing tool 100. For example, information handling system 122 may process the information from formation testing tool 100 for determination of fluid contamination. Information handling system 122 may also determine additional properties of the fluid sample (or reservoir fluid), such as component concentrations, pressure-volume-temperature properties (e.g., bubble point, phase envelop prediction, etc.) based on the fluid characterization. This processing may occur at surface 112 in real-time. Alternatively, the processing may occur downhole or at surface 112 or another location after recovery of formation testing tool 100 from wellbore 104. Alternatively, the processing may be performed by an information handling system 122 in wellbore 104, such as fluid analysis module 118. The resultant fluid contamination and fluid properties may then be transmitted to surface 112, for example, in real-time.

It should be noted that in some examples, a gas chromatographer 132 may be disposed on surface 112 and analyze samples captures by formation testing tool 100. For example, fluid analysis module 118 may capture fluid samples and bring them to the surface 112 for analysis at the wellsite. As illustrated, gas chromatographer 132 may be disposed in vehicle 110. However, gas chromatographer 132 may be a standalone assembly that may be available at the wellsite. Additionally, information handling system 122 may be connected to gas chromatographer 132 through communication link 120. In examples, gas chromatographer 132 may operate and function as described above.

Referring now to FIG. 2, FIG. 2 is a schematic diagram of a formation testing tool 100 disposed on a drill string 200 in a drilling operation. Formation testing tool 100 may be used to obtain a fluid sample, for example, a fluid sample of a reservoir fluid from subterranean formation 106. The reservoir fluid may be contaminated with well fluid (e.g., drilling fluid) from wellbore 104. As described herein, the fluid sample may be analyzed to determine fluid contamination and other fluid properties of the reservoir fluid. As illustrated, a wellbore 104 may extend through subterranean formation 106. While the wellbore 104 is shown extending generally vertically into the subterranean formation 106, the principles described herein are also applicable to wellbores that extend at an angle through the subterranean formation 106, such as horizontal and slanted wellbores. For example, although FIG. 2 shows a vertical and low inclination angle well, high inclination angle or horizontal placement of the well and equipment is also possible. It should further be noted that while FIG. 2 generally depicts a land-based operation, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

As illustrated, a drilling platform 202 may support a derrick 204 having a traveling block 206 for raising and lowering drill string 200. Drill string 200 may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art. A kelly 208 may support drill string 200 as it may be lowered through a rotary table 210. A drill bit 212 may be attached to the distal end of drill string 200 and may be driven either by a downhole motor and/or via rotation of drill string 200 from the surface 112. Without limitation, drill bit 212 may include, roller cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, and the like. As drill bit 212 rotates, it may create and extend wellbore 104 that penetrates various subterranean formations 106. A pump 214 may circulate drilling fluid through a feed pipe 216 to kelly 208, downhole through interior of drill string 200, through orifices in drill bit 212, back to surface 112 via annulus 218 surrounding drill string 200, and into a retention pit 220.

Drill bit 212 may be just one piece of a downhole assembly that may include one or more drill collars 222 and formation testing tool 100. Formation testing tool 100, which may be built into the drill collars 222) may gather measurements and fluid samples as described herein. One or more of the drill collars 222 may form a tool body 114, which may be elongated as shown on FIG. 2. Tool body 114 may be any suitable material, including without limitation titanium, stainless steel, alloys, plastic, combinations thereof, and the like. Formation testing tool 100 may be similar in configuration and operation to formation testing tool 100 shown on FIG. 1 except that FIG. 2 shows formation testing tool 100 disposed on drill string 200. Alternatively, the formation testing tool 100 may be lowered into the wellbore after drilling operations on a wireline.

Formation testing tool 100 may further include one or more sensors 116 for measuring properties of the fluid sample reservoir fluid, wellbore 104, subterranean formation 106, or the like. The properties of the fluid are measured as the fluid passes from the formation through the tool and into either the wellbore or a sample container. As fluid is flushed in the near wellbore region by the mechanical pump, the fluid that passes through the tool generally reduces in drilling fluid filtrate content, and generally increases in formation fluid content. Formation testing tool 100 may be used to collect a fluid sample from subterranean formation 106 when the drilling fluid filtrate content has been determined to be sufficiently low. Sufficiently low depends on the purpose of sampling. For some laboratory testing below 10% drilling fluid contamination is sufficiently low, and for other testing below 1% drilling fluid filtrate contamination is sufficiently low. Sufficiently low also depends on the nature of the formation fluid such that lower standards are generally needed, the lighter the oil as designated with either a higher GOR or a higher API gravity. Sufficiently low also depends on the rate of cleanup in a cost benefit analysis since longer pump out times utilized to incrementally reduce the contamination levels may have prohibitively large costs. As previously described, the fluid sample may include a reservoir fluid, which may be contaminated with a drilling fluid or drilling fluid filtrate. Formation testing tool 100 may obtain and separately store different fluid samples from subterranean formation 106 with fluid analysis module 118. Fluid analysis module 118 may operate and function in the same manner as described above. However, storing of the fluid samples in the formation testing tool 100 may be based on the determination of the fluid contamination. For example, if the fluid contamination exceeds a tolerance, then the fluid sample may not be stored. If the fluid contamination is within a tolerance, then the fluid sample may be stored in the formation testing tool 100.

As previously described, information from formation testing tool 100 may be transmitted to an information handling system 122, which may be located at surface 112. As illustrated, communication link 120 (which may be wired or wireless, for example) may be provided that may transmit data from formation testing tool 100 to an information handling system at surface 112. Information handling system may include a processing unit 124, a monitor 126, an input device 128 (e.g., keyboard, mouse, etc.), and/or computer media 130 (e.g., optical disks, magnetic disks) that may store code representative of the methods described herein. In addition to, or in place of processing at surface 112, processing may occur downhole (e.g., fluid analysis module 118). In examples, information handling system 122 may perform computations to estimate clean fluid composition.

As previously described above, a gas chromatographer 132 may be disposed on surface 112 and analyze samples captures by formation testing tool 100. For example, fluid analysis module 118 may capture fluid samples and bring them to the surface 112 for analysis at the wellsite. As illustrated, gas chromatographer 132 may be a standalone assembly that may be available at the wellsite. Additionally, information handling system 122 may be connected to gas chromatographer 132 through communication link 120. In examples, gas chromatographer 132 may operate and function as described above.

FIG. 3 illustrates a schematic of formation testing tool 100. As illustrated, downhole tool 100 may include a power telemetry section 302 through which formation testing tool 100 may communicate with other actuators and sensors in a conveyance (e.g., conveyance 102 on FIG. 1 or drill string 200 on FIG. 2), and/or the conveyance's communications system, such as information handling system 122 (e.g., referring to FIG. 1). In examples, power telemetry section 302 may also be a port through which the various actuators (e.g., valves) and sensors (e.g., temperature and pressure sensors) in downhole tool 100 may be controlled and monitored. In one or more examples, control and monitoring may be performed by an information handling system 122.

As mentioned above, information from formation testing tool 100 may be gathered and/or processed by information handling system 122 (e.g., referring to FIGS. 1 and 2). The processing may be performed in real-time during data acquisition or after recovery of formation testing tool 100. Processing may alternatively occur downhole or may occur both downhole and at surface 112. In some examples, signals recorded by formation testing tool 100 may be conducted to information handling system 122 by way of conveyance. Information handling system 122 may process the signals, and the information contained therein may be displayed for an operator to observe and stored for future processing and reference. Information handling system 122 may also contain an apparatus for supplying control signals and power to formation testing tool 100.

In examples, formation testing tool 100 may include one or more enhanced probe sections 304 and stabilizers 324. Each enhanced probe section may include a dual probe section 306 or a sampling probe section 308. Both of which may extract reservoir fluid from the formation 106 and deliver said reservoir fluid to a flow line 310 that extends from one end of formation testing tool 100 to the other. Without limitation, dual probe section 306 includes two probes 312, 314 which may extend from formation testing tool 100 and press against the inner wall of wellbore 104 (e.g., referring to FIG. 1). Probe flow lines 316 and 318 may connect probes 312, 314 to flow line 310 and allow for continuous fluid flow from formation 106 to flow line 310. A high-volume bidirectional pump 320 may be used to pump fluids from formation 106, through probe flow lines 316, 318 and to flow line 310. Alternatively, a low volume bidirectional pump 322 may be used to extract reservoir fluid from formation 106. Low volume bidirectional pump 322 may be able to handle from 0.1 mL to 500 mL of volume of fluid, from 1 mL to 400 mL, from 5 mL to 250 mL, from 10 mL to 100 mL, from 20 mL to 75 mL, or from 25 mL to 50 mL for example. Two standoffs or stabilizers 324, 326 hold formation testing tool 100 in place as probes 312, 314 press against the wall of wellbore 104. At least one of stabilizers 324, 326 may be disposed on the opposite side of formation testing tool 100 of at least one of probes 312, 314. In examples, probes 312, 314 and stabilizers 324, 326 may be retracted when formation testing tool 100 may be in motion and probes 312, 314 and stabilizers 324, 326 may be extended to sample the reservoir fluids at any suitable location in wellbore 104. As illustrated, probes 312, 314 may be replaced, or used in conjunction with, sampling probe section 308. Sampling probe section 308 may operate and function as discussed above for probes 312, 314 but with a focused sampling probe 328. Other probe examples may include, but are not limited to, oval probes, packers, or circumferential probes.

In examples, flow line 310 may connect other parts and sections of formation testing tool 100 to each other. For example, formation testing tool 100 may include a second high-volume bidirectional pump 330 for pumping fluid through flow line 310 to one or more multi-chamber sections 332, one or more fluid density modules 334, and/or one or more dynamic subsurface optical measurement tools 336.

FIG. 4 illustrates a focused sampling probe 328 in sampling probe section 308. Focused sampling probe 328 is a dual flow probe comprising a guard probe 400 with a guard surface that captures contaminants and a clean probe 402 with a sample (inner) surface that captures clean fluid. As illustrated in FIG. 4, sampling probe section 308 may comprise a focused sampling probe 328, which may operate and function as described below. Guard probe 400 is operable to protect clean probe 402 from external forces, such as from collisions or interactions with a side of a drill string or casing while conveying formation testing tool 100 downhole to a target sampling location.

FIG. 4 shows focused sampling probe 328 having an aperture 410. Aperture 410 is an oval-like structure that is molded to sealing pad 412 to facilitate sealing. Other geometries are possible, but the basic principle is to support sealing pad 412 such that it seals against the borehole or wellbore without drawing in free fluid from a flow area. In some embodiments, sealing pad 412 may be retractable. Aperture 410 may be operable to seal sealing pad 412 to a borehole wall. Aperture 410 may comprise metal, such as steel. Focused sampling probe 328 may be further equipped with a screen assembly (not shown) which, upon retracting of sealing pad 412, may allow for a wiper cylinder to push mudcake or sand from a screen area of sample probe 402. In alternative embodiments, sample probe 402 may comprise a gravel pack type of material instead of a screen to screen for very fine particles into one or more probe flow lines 316 and 318 (referring to FIG. 3), or into one or more flowlines fluidically connected to flow line 310. One skilled in the art should understand that in the above-described aspects of the invention, the probe assembly has a large exposure volume sufficient for testing and sampling large and elongated sections of formation 106. In operation, pressure at sample probe 402 may be reduced, thereby drawing in reservoir fluids from formation 106 through borehole wall to which sealing pad 412 is sealed. In this manner, fluid samples may be collected and transported via probe flow lines 316 and 318.

For example, during reservoir fluid sampling operations, focused sampling probe 328 may be pressed against the inner wall of wellbore 104 (e.g., referring to FIG. 1) to create a sealed fluid connection between formation 106 (e.g., referring to FIG. 1 or 2) and flow line 310. High-volume bidirectional pump 320 is then activated to extract reservoir fluid from formation 106 into flow line 310 (e.g., referring to FIG. 3). High-volume bidirectional pump 320 ensures continued extraction of reservoir fluid from formation 106 while fluid analysis module 118 monitors drilling fluid filtrate contamination present in reservoir fluid. Fluid analysis module 118 may include at least one sensor that may continuously monitor a reservoir fluid such as optical sensors, acoustic sensors, electromagnetic sensors, conductivity sensors, resistivity sensors, selective electrodes, density sensors, mass sensors, thermal sensors, chromatography sensors, viscosity sensors, bubble point sensors, fluid compressibility sensors, flow rate sensors. Sensors may measure a contrast between drilling fluid filtrate properties and formation fluid properties.

FIG. 5 is a numerical simulation of the contamination level of reservoir fluid inside flow line 310 detected by fluid analysis module 118 (e.g., referring to FIG. 3) as a function of time according to embodiments of the present disclosure. The numerical simulation was conducted to simulate the cleanup effect of the flow area due to a change of ratio of flow rates between the pumping flow rate inside the guard probe 400 and the pumping flow rate inside the clean probe 402 when the contamination reaches low level (˜10%) after 4 hours of pumping at a constant ratio. During the first 4 hours, the flow rate inside guard probe 400 and the flow rate inside clean probe 402 is maintained at a ratio of flow rates around 2:1. The contamination decreases gradually until 4 hours where the drilling fluid filtrate represents 10% of the reservoir fluid inside flow line 310. After 4 hours, the flow rate inside guard probe 400 is increased by 50% while the flow rate inside clean probe 402 is kept constant. The increase of flow rate inside guard probe 400 may be obtained by manipulating valve 350 (referring to FIG. 3) opening it further through information handling system 122. Alternatively, or in addition, the flow rate inside clean probe 402 may be decreased by manipulating valve 360 (referring to FIG. 3) closing it further through information handling system 122. Conventionally, the flow rate is controlled through bidirectional pump 320 (referring to FIG. 3) by manipulating the stroke rate.

This change of ratio of flow rates causes the pressure near guard probe 400 flow area to decrease further to below the pressure of the clean probe 402 area as illustrated in FIG. 6. The increase of differential pressure between guard probe 400 and clean probe 402 creates a stronger guarding effect preventing drilling fluid filtrate from entering clean probe 402 flow area as drilling fluid filtrate is sucked into guard probe 400 line. As a result, the drilling fluid filtrate contamination in clean probe 402 is reduced suddenly and rapidly, enabling the acquisition or sampling of clean reservoir fluid faster without prolonging pumping.

FIG. 6 represents the simulation of the pressure as a function of the radial distance around clean probe 402 when the flow rate inside guard probe 400 is increased by 50% while the flow rate inside clean probe 402 is kept constant after 4 hours labelled “2. Flow rate inside guard increased by 50%” in FIG. 5. The drilling fluid filtrate contamination is sucked by guard probe 400 and decreases significantly as the reservoir fluid is sucked by clean probe 402. For this simulation, density was used as a marker to differentiate drilling fluid filtrate from reservoir fluid. As both the densities of pure drilling fluid filtrate and pure reservoir fluid are known for this simulation, the contamination level at any given time may be calculated from the mixture density.

FIG. 7 represents the simulation of the formation pressure around clean probe 402 versus the pressure around guard probe 400 when the flow rate inside guard probe 400 is increased by 50% while the flow rate inside clean probe 402 is kept constant after 4 hours in FIG. 5. As fluid is pumped into the probes, the pressure around the probes will reduce, forming pressure gradient field. The pressure gradient field can be manipulated by changing flow rates of either probe.

While the flow rate inside guard probe 400 was increased by 50% for the simulations represented in FIGS. 5-7, the ratio may be modified by any amount by either increasing the flow rate inside guard probe 400 or decreasing the flow rate inside clean probe 402 or any combination thereof. The ratio between the flow rate inside guard probe 400 and the flow rate inside clean probe 402 may be increased from about 5% to about a factor of 100, or from about 10% to a factor of about 50, from about 20% to a factor of about 25, from about 25% to a factor of about 20, from about 50% to a factor of about 25, from about 50% to a factor of about 10, from about 75% to a factor of about 5, or anything in between, for example. In embodiments, the ratio between the flow rate inside guard probe 400 and the flow rate inside clean probe 402 may be changed (increased or decreased) from about 50% to about a factor of 10.

Further, while the change of ratio was triggered when the drilling fluid filtrate reached a pre-determined value of 10% of the reservoir fluid inside flow line 310 for the simulations in FIGS. 5-7, any number may be chosen by the operator including a pre-determined value from 75% to 5% or any number in between, or more specifically 50%, 40%, 30%, 25%, 20%, 15%, 10%, 7.5% or less, for example.

The preceding description provides various embodiments of systems and methods of use which may contain different method steps and alternative combinations of components. It should be understood that, although individual embodiments may be discussed herein, the present disclosure covers all combinations of the disclosed embodiments, including, without limitation, the different component combinations, method step combinations, and properties of the system.

Statement 1. A method comprising: conveying a formation testing tool into a wellbore, wherein the formation testing tool includes: at least one focused sampling probe comprising a dual flow probe with a guard probe and a clean probe; at least two pumps disposed within the formation testing tool with one pump connected to the clean probe and at least one flow line, and a second pump connected to the guard probe and at least a second flow line; and at least one stabilizer disposed on an opposite side of the formation testing tool of the at least one focused sampling probe; pumping reservoir fluid from a downhole formation from the guard probe to the at least one flow line at a first flow rate; pumping reservoir fluid from a downhole formation from the clean probe to a second flow line at a second flow rate, wherein a ratio of flow rates between the first flow rate and the second flow rate is held constant until reaching a first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe; changing the ratio of flow rates between the first and second flow rates; and sampling a reservoir fluid when reaching a second pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Statement 2. The method of Statement 1, wherein the ratio of flow rates is from 10:1 to 1:1 before reaching the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Statement 3. The method of any one of previous Statements 1 or 2, wherein the ratio of flow rates is from 3:1 to 1:1 before reaching the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Statement 4. The method of any one of previous Statements 1-3, wherein the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe is from 20% to 8%.

Statement 5. The method of any one of previous Statements 1-4, wherein the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe is from 12% to 8%.

Statement 6. The method of any one of previous Statements 1-5, wherein the ratio of flow rates is increased from about 50% to about a factor of 10.

Statement 7. The method of any one of previous Statements 1-6, wherein the ratio of flow rates is increased from about 25% to a factor of about 5.

Statement 8. The method of any one of previous Statements 1-7, wherein the ratio of flow rates is changed by increasing the first flow rate.

Statement 9. The method of any one of previous Statements 1-8, wherein the ratio of flow rates is changed by decreasing the second flow rate.

Statement 10. The method of any one of previous Statements 1-9, wherein the ratio of flow rates is changed by increasing the first flow rate and by decreasing the second flow rate.

Statement 11. non-transitory computer readable medium having data stored therein representing a software executable by a computer, the software executable comprising instructions configured to: pumping reservoir fluid from a downhole formation from a guard probe to at least one flow line of a formation testing tool at a first flow rate, wherein the formation testing tool comprises: at least one focused sampling probe comprising a dual flow probe with the guard probe and a clean probe; at least two pumps disposed within the formation testing tool with one pump connected to the clean probe and at least one flow line, and a second pump connected to the guard probe and at least a second flow line; and at least one stabilizer disposed on an opposite side of the formation testing tool of the at least one focused sampling probe; pumping reservoir fluid from the downhole formation from the clean probe to the second flow line at a second flow rate, wherein a ratio of flow rates between the first flow rate and the second flow rate is held constant until reaching a first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe; changing the ratio of flow rates between the first and second flow rates; and sampling a reservoir fluid when reaching a second pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Statement 12. The non-transitory computer readable medium of Statement 11, wherein the ratio of flow rates is from 10:1 to 1:1 before reaching the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Statement 13. The non-transitory computer readable medium of Statement 11 or Statement 12, wherein the ratio of flow rates is from 3:1 to 1:1 before reaching the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

Statement 14. The non-transitory computer readable medium of any one of previous Statements 11-13, wherein the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe is from 20% to 8%.

Statement 15. The non-transitory computer readable medium of any one of previous Statements 11-14, wherein the first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe is from 12% to 8%.

Statement 16. The non-transitory computer readable medium of any one of previous Statements 11-15, wherein the ratio of flow rates is increased from about 50% to about a factor of 10.

Statement 17. The non-transitory computer readable medium of any one of previous Statements 11-16, wherein the ratio of flow rates is increased from about 25% to a factor of about 5.

Statement 18. The non-transitory computer readable medium of any one of previous Statements 11-17 wherein the ratio of flow rates is changed by increasing the first flow rate.

Statement 19. The non-transitory computer readable medium of any one of previous Statements 11-18, wherein the ratio of flow rates is changed by decreasing the second flow rate.

Statement 20. The non-transitory computer readable medium of any one of previous Statements 11-19, wherein the ratio of flow rates is changed by increasing the first flow rate and by decreasing the second flow rate.

It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.

Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, the disclosure covers all combinations of all those embodiments. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.