Patent Publication Number: US-11649724-B2

Title: Formation testing and sampling tool for stimulation of tight and ultra-tight formations

Description:
BACKGROUND 
     Wells may be drilled at various depths to access and produce oil, gas, minerals, and other naturally-occurring deposits from subterranean geological formations. The drilling of a well is typically accomplished with a drill bit that is rotated within the well to advance the well by removing topsoil, sand, clay, limestone, calcites, dolomites, or other materials. 
     During drilling operations, sampling operations may be performed to collect a representative sample of formation or reservoir fluids (e.g., hydrocarbons) to further evaluate drilling operations and production potential, or to detect the presence of certain gases or other materials in the formation that may affect well performance. 
     Tight and ultra-tight reservoirs that are also known as secondary reservoirs are defined as all petroleum resources that must be produced economically from low permeability and low porosity reservoirs by stimulation treatment (e.g. acid stimulation, hydraulic fracturing or both combined) are referred to as tight oil, without limitations of lithology and oil quality. Due to the low porosity and permeability within these formations, current wireline formation testing tools are incapable of collecting representative hydrocarbon samples due to the inability of such reservoirs to flow naturally or efficiently. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments. 
         FIG.  1 A  illustrates a schematic view of a well in which an example embodiment of a fluid sample system is deployed. 
         FIG.  1 B  illustrates a schematic view of another well in which an example embodiment of a fluid sample system is deployed. 
         FIG.  2    illustrates a schematic view of an example embodiment of a fluid sampling tool. 
         FIG.  3    illustrates an enlarged schematic view of an example embodiment the fluid sampling tool of  FIG.  2   . 
         FIGS.  4 A- 4 E  illustrated side views of different types of etching in a formation. 
         FIGS.  5 A- 5 E  illustrate a cross section of each view in  FIGS.  4 A- 4 E . 
         FIGS.  6 A and  6 B  illustrate pre-job pressure-rate simulations. 
         FIGS.  7 A and  7 B  illustrate a schematic of a packer assembly that includes one or more ports, during stimulation operations. 
         FIG.  8    is a flowchart for stimulating a formation. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure relates to subterranean operations and, more particularly, embodiments disclosed herein provide methods and systems for capture and measurement of fluids and formation properties in an area of interest. Specifically, fluid and rock properties in an ultra-tight formation using a formation tester. An ultra-tight formation is defined as a formation that has characteristics of low permeability and low porosity. Generally, stimulation treatments (e.g. acid stimulation, hydraulic fracturing or both combined) must be utilized to remove the “tight oil” from the formation. Tight oil is defined as the oil resources that is preserved and accumulated in low porosity (&lt;12%) and low permeability (&lt;0.1 mD). In this range of porosity and permeability, wireline formation testing tools are not capable of collecting representative hydrocarbon samples due to the inability of such reservoirs to flow naturally or efficiently by its definition with all existing sampling tools technology in the market. Permeability and flow within a formation is found using the following equation for Darcy&#39;s law: 
                   q   =       -     K   μ       ⁢   Δ   ⁢   P             (   1   )               
which shows the direct relation between permeability “K” and fluid flowing rate “q.” Equation (1) includes μ, which represents fluid viscosity and further shows how a low K value will produce a high pressure drawdown (ΔP) and very low flowing rate “q,” which may identify ultra-low mobility of fluids.
 
     Ultra-low mobility in tight formations prevent conventional formation testers from obtaining both fluid and rock properties. Discussed below are systems and methods for a formation testing tool to address the needs specific to an ultra-tight formation or a tight formation that includes characteristics of ultra-low mobility of fluids. For example, the formation testing tool may be able to inject, flow-back, or place the stimulation fluid(s) facing the target formation with a controlled increase in pressure that may exceed or not exceed fracturing pressure, which is based on the type of stimulation operation. The utilization of a dual port straddle packer assembly controls the mode of operation to be used depending on the nature of the formation and stimulation ability. During operations, the formation testing tool may carry large volumes of stimulation fluid(s) within the formation testing tool with no interaction between the fluids and the carrying tanks. Additionally, the formation testing tool may have the ability to control the stimulation fluids characteristics by mixing the simulation fluids with inhibitor and/or catalyzers in-situ conditions in order to enhance the simulation fluids results and prevent corrosion effect on the formation testing tool from the simulation fluids. In other methods, the formation testing tool may use one or more combination logs including but not limited to open hole logs, caliper, corrosion, and cement image logs to optimize the perforation interval. For example, in a cased hole environment cement bond and casing imaging logs may be utilized for stimulation operations to ensure that the injected stimulation fluid is efficiently directed into the perforated formation and not leaking into a channel behind a casing in situations with poor zonal isolation. During operations, the logs may be utilized for evaluating zones of interest in an open hole environment to evaluate parameters such as, and not limited to, borehole profile and size, quality of the rock, etc. In addition, Pre and Post pressure build-up may be measured to evaluate the stimulation efficiency as a direct measurement. 
     The fluid sampling tools described herein may vary in design, but embodiments of the fluid sampling tools typically may include an inlet, an outlet, and a sampling chamber. Embodiments may further include two or more sampling chambers. The inlet and outlet may be fluidly connected to the fluid within the wellbore that is being extracted from a subterranean formation. In sampling operation, a fluid sample may be gathered into the sampling chamber from the formation for analysis. 
     The fluid sampling tools, systems and methods described herein may be used with any of the various techniques employed for evaluating a well, including without limitation wireline formation testing (WFT), measurement while drilling (MWD), and logging while drilling (LWD). The various tools and sampling units described herein may be delivered downhole as part of a wireline-delivered downhole assembly or as a part of a drill string. It should also be apparent that given the benefit of this disclosure, the apparatuses and methods described herein have applications in downhole operations other than drilling, and may also be used after a well is completed. 
       FIG.  1 A  illustrates a fluid sampling and analysis system  100  according to an illustrative embodiment used in a well  102  having a wellbore  104  that extends from a surface  108  of well  102  to or through a subterranean formation  112 . While wellbore  104  is shown extending generally vertically into subterranean formation  112 , the principles described herein are also applicable to wellbores that extend at an angle through subterranean formations  112 , such as horizontal and slanted wellbores. For example, although  FIG.  1 A  shows wellbore  104  that is vertical or low inclination, high inclination angle or horizontal placement of wellbore  104  and equipment is also possible. In addition, it should be noted that while  FIG.  1 A  generally depicts a land-based operation, those skilled in the art should 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. 
     Well  102  is illustrated with fluid sampling and analysis system  100  being deployed in a drilling assembly  114 . In the embodiment illustrated in  FIG.  1 A , well  102  is formed by a drilling process in which a drill bit  116  is turned by a drill string  120  that extends from drill bit  116  to surface  108  of well  102 . Drill string  120  may be made up of one or more connected tubes or pipes, of varying or similar cross-section. Drill string  120  may refer to the collection of pipes or tubes as a single component, or alternatively to the individual pipes or tubes that include the string. The term “drill string” is not meant to be limiting in nature and may refer to any component or components that are capable of transferring rotational energy from the surface of the well to the drill bit. In several embodiments, drill string  120  may include a central passage disposed longitudinally in drill string  120  and capable of allowing fluid communication between surface  108  of well  102  and downhole locations. 
     At or near surface  108  of well  102 , drill string  120  may include or be coupled to a kelly  128 . Kelly  128  may have a square, hexagonal, octagonal, or other suitable cross-section. In examples, kelly  128  may be connected at one end to the remainder of drill string  120  and at an opposite end to a rotary swivel  132 . As illustrated, kelly  120  may pass through a rotary table  136  that is capable of rotating kelly  128  and thus the remainder of drill string  120  and drill bit  116 . Rotary swivel  132  should allow kelly  128  to rotate without rotational motion being imparted to rotary swivel  132 . A hook  138 , cable  142 , traveling block (not shown), and hoist (not shown) may be provided to lift or lower the drill bit  116 , drill string  120 , kelly  128  and rotary swivel  132 . Kelly  128  and swivel  132  may be raised or lowered as needed to add additional sections of tubing to drill string  120  as drill bit  116  advances, or to remove sections of tubing from drill string  120  if removal of drill string  120  and drill bit  116  from well  102  is desired. 
     A reservoir  144  may be positioned at surface  108  and holds drilling fluid  148  for delivery to well  102  during drilling operations. A supply line  152  may fluidly couple reservoir  144  and the inner passage of drill string  120 . A pump  156  may drive drilling fluid  148  through supply line  152  and downhole to lubricate drill bit  116  during drilling and to carry cuttings from the drilling process back to surface  108 . After traveling downhole, drilling fluid  148  returns to surface  108  by way of an annulus  160  formed between drill string  120  and wellbore  104 . At surface  108 , drilling mud  148  may returned to reservoir  144  through a return line  164 . Drilling mud  148  may be filtered or otherwise processed prior to recirculation through well  102 . 
     FIB.  1 B illustrates a schematic view of another embodiment of well  102  in which an example embodiment of fluid analysis system  100  may be deployed. As illustrated, fluid analysis system  100  may be deployed as part of a wireline assembly  115 , either onshore of offshore. As illustrated, wireline assembly  115  may include a winch  117 , for example, to raise and lower a downhole portion of wireline assembly  115  into well  102 . As illustrated, fluid analysis system  100  may include fluid sampling tool  170  attached to winch  117 . In examples, it should be noted that fluid sampling tool  170  may not be attached to winch  117 . Fluid sampling tool  170  may be supported by rig  172  at surface  108 . 
     Fluid sampling tool  170  may be tethered to winch  117  through wireline  174 . While  FIG.  1 B  illustrates wireline  174 , it should be understood that other suitable conveyances may also be used for providing mechanical conveyance to fluid sampling tool in well  102 , including, but not limited to, slickline, coiled tubing, pipe, drill pipe, drill string, downhole tractor, or the like. In some examples, the conveyance may provide mechanical suspension, as well as electrical connectivity, for fluid sampling tool  170 . Wireline  174  may include, in some instances, a plurality of electrical conductors extending from winch  117 . By way of example, wireline  174  may include an inner core of seven electrical conductors (not shown) covered by an insulating wrap. An inner and outer steel armor sheath may be wrapped in a helix in opposite directions around the conductors. The electrical conductors may be used for communicating power and telemetry downhole to fluid sampling tool  170 . 
     With reference to both  FIGS.  1 A and  1 B , operation of fluid sampling tool  170  for sample collection will now be described in accordance with example embodiments. Fluid sampling tool  170  may be raised and lowered into well  102  on drill string  120  (e.g., referring to  FIG.  1 A ) and wireline  174  (e.g., referring to  FIG.  1 B ). Fluid sampling tool  170  may be positioned downhole to obtain fluid samples from the subterranean formation  112  for analysis. The formation fluid and, thus the fluid sample may be contaminated with, or otherwise contain, the target component. In some embodiments, the target component may be contained in the fluid sample in small quantities, for example, less than 500 parts per million (“ppm”). Additionally, the target component may be present in the fluid sample in an amount from about 1 ppm to about 500 ppm, about 100 ppm to about 200 ppm, about 1 ppm to about 100 ppm, or about 5 to about 10 ppm. Fluid sampling tool  170  may be operable to measure, process, and communicate data regarding subterranean formation  112 , fluid from subterranean formation  112 , or other operations occurring downhole. After recovery, the fluid sample may be analyzed, for example, to quantify the concentration of the target component. This information, including information gathered from analysis of the fluid sample, allows well operators to determine, among other things, the concentration the target component within the fluid being extracted from subterranean formation  112  to make intelligent decisions about ongoing operation of well  102 . In some embodiments, the data measured and collected by fluid sampling tool  170  may include, without limitation, pressure, temperature, flow, acceleration (seismic and acoustic), and strain data. As described in more detail below, fluid sampling tool  170  may include a communications subsystem, including a transceiver for communicating using mud pulse telemetry or another suitable method of wired or wireless communication with a surface controller  184 . The transceiver may transmit data gathered by fluid sampling tool  170  or receive instructions from a well operator via surface controller  184  to operate fluid sampling tool  170 . 
     Referring now to  FIG.  2   , an example embodiment of a fluid sampling tool  170  is illustrated as a tool for gathering fluid samples from a formation for subsequent analysis and testing. It should be understood that the fluid sampling tool  170  shown on  FIG.  2    is merely illustrative and the example embodiments disclosed herein may be used with other tool configurations. In an embodiment, fluid sampling tool  170  includes a transceiver  202  through which fluid sampling tool  170  may communicate with other actuators and sensors in a conveyance (e.g., drill string  120  on  FIG.  1 A  or wireline  174  on  FIG.  1 B ), the conveyance&#39;s communications system, and with a surface controller (surface controller  184  on  FIG.  1 A ). In an embodiment, transceiver  202  is also the port through which various actuators (e.g. valves) and sensors (e.g., temperature and pressure sensors) in fluid sampling tool  170  are controlled and monitored by, for example, a computer in another part of the conveyance or by surface controller  184 . In an embodiment, transceiver  202  includes an information handling system that exercises the control and monitoring function. 
     In examples, the information handling system may connect to sensors and other devices by a communication link (which may be wired or wireless, for example) which may transmit data to information handling system. While the information handling system is disposed in transceiver  202 , a second information handling system may be disposed at the surface. This may allow for data transmission from fluid sampling tool  170  to the surface in real time. Additionally, there may only be an information handling system at the surface, which receives data and measurements from fluid sampling tool  170  through a direct or wireless connection. In examples, the information handling system may include a personal computer, a video display, a keyboard (i.e., other input devices.), and/or non-transitory computer-readable media (e.g., optical disks, magnetic disks) that may store code representative of the methods described herein. Likewise, the information handling system may process measurements taken by one or more sensors automatically. During operations, software, algorithms, and modeling may be performed by the information handling system. The information handling system may perform steps, run software, perform calculations, and/or the like automatically, through automation (such as through artificial intelligence (“AI”), dynamically, in real-time, and/or substantially in real-time. The information handling system may be connected to all control systems and device to control all operations and functions of fluid sampling tool  170 , as well as record, transmit, or process measurements and acquired data. 
     Fluid sampling tool  170  may include a packer assembly  204 . In examples, packer assembly  204  may include one or more inflatable packers  208  that are attached to the outside of packer assembly  204 . Inflatable packers  208  include at least a first inflatable packer  208   a  longitudinally spaced from a second inflatable packer  208   b  along packer assembly  204 . During operations, inflatable packers  208  may be expanded and/or inflated (not illustrated). When inflatable packers  208  are expanded, inflatable packers  208  may seal a section within well  102  (e.g., referring to  FIG.  1   ), and create an inflatable packer space  182  between inflatable packers  208 . Inflatable packers  208  may trap fluid within inflatable packer space  182 , where the fluid may be drilling fluid, or other downhole fluid. 
     As illustrated in  FIG.  2   , a channel  206  extends from one end of the fluid sampling tool  170  to the other. Channel  206  may be connected to other tools or portions of the fluid sampling tool  170  arranged in series. Fluid sampling tool  170  may also include a single or multiple flow-control pump-out section  210 , which includes a pump  212  for pumping fluid through the channel  206 . The fluid sampling tool  170  also includes one or more chambers, such as multi-chamber sections  214 . 
     With additional reference to  FIG.  3   , multi-chamber sections  214  include multiple sample chambers  232 . While  FIGS.  2  and  3    show the multi-chamber sections  214  having three sample chambers  232 , it will be understood that multi-chamber sections  214  may have any number of sample chambers  232  and may in fact be single chamber sections. In some embodiments, sample chambers  232  may be coupled to channel  206  through respective chamber valves  320 ,  325 ,  330 . Formation fluid may be directed from channel  206  to a selected one of sample chambers  232  by opening the appropriate one of chamber valves  320 ,  325 ,  330 . Chamber valves  320 ,  325 ,  330  may be configured such that when one of chamber valves  320 ,  325 ,  330  is open the others are closed. 
     In some embodiments, multi-chamber section  214  may include a path  335  from channel  206  to annulus  160  through an annulus valve  340 . Annulus valve  340  may be open during the draw-down period when fluid sampling tool  170  is clearing mud cake, drilling mud, and other contaminants into the annulus before clean formation fluid is directed to one of sample chambers  232 . A check valve  345  may prevent fluids from annulus  160  from flowing back into channel  206  through path  335 . As such, the multi-chamber sections  214  may include a path  350  from sample chambers  223  to annulus  160 . 
     Referring back to  FIG.  2   , multi-chamber section  214  may be further connected to a storage section  234 . In examples, there may be one or more storage sections  234 , as illustrates there are two storage sections  234 . Within storage section  234  may be a single storage tank  236 . However, there may be multiple storage tanks  236  within storage section  234 . In examples, storage tanks  236  may operate and function to hold stimulation fluids and release the stimulation fluids at an area of interest. During operations, storage tanks  236  may be controlled by chamber valve section “CVS”  214 . CVS  214  controls the selection of which storage tank  236  may be opened or closed at the required time of operations. Controlling of the opening and closing of each storage tank  236  may be performed by one or more valves  216 . When opened, stimulation fluids may be removed from each storage tank  236  separately or at the same time. Pump  212  may move stimulation fluid from storage tank  236  to channel  206 , which may allow for stimulation fluid to move through fluid sampling tool  170  to packer assembly  204 . The stimulation fluid may be expelled through one or more exhaust ports  218  and  219  in packer  204 . With one or more inflatable packers  208  deployed, inflatable packer space  182  may allow for stimulation fluid to target a specific zone of interest in a formation. The stimulation fluid may be injected directly into the formation or may be placed within the area separated by packer  204  but not directly injected into the formation. 
     During sampling operations, as discussed above, an objective may be to obtain fluid and rock properties. However, in ultra-tight/secondary reservoir current methods may not be applicable. Specifically, the rock formation may not allow for fluid sampling and analysis system  100  to draw fluid from subterranean formation  112  (e.g., referring to  FIG.  2   ). To perform sampling operations, stimulation fluids may be carried to a zone of interest in which sampling operations may be performed. Stimulation fluids may include different acid types and concentrations such as and not limited to HCL or H2SO4 which is known by its enhancement effects for certain rock types due to its chemical reaction causing an increase in the rock porosity and therefore rock permeability. Another stimulation fluid is Alkaline Surfactant Polymers (ASP), which is known by its effect of altering rock wettability causing an enhancement for better fluid movement and productivity, viscosity reducers chemicals which helps in reducing the hydrocarbon viscosity to ease its flow into the sampling tool, and/or the like. Most stimulation fluid is known by its corrosive behavior, which require a special treatment by using and designing specific inhibitor blends such as (HAI- 85 M) to inhibit acid corrosion of storage tanks  236  within fluid sampling tool  170 . The stimulation fluid may contain any number of combination of surfactants, solvents and dispersants that enables it to provide corrosion protection in acid at temperatures up to 177° C. against the tool interiors while preserving its chemical properties for targeted reservoir enhancement. 
     Holding the stimulation fluids and inhibitors within fluid sampling and analysis system  100  allows for precisely targeting the required zone of interest with a pre-designed interval spacing and stimulation fluid volume to be injected as well as monitoring downhole pressure improvement while stimulating followed by a flow-back for reservoir fluid sampling and characterization. Different stimulation fluid(s) may be carried downhole within fluid sampling tool  170  in well  102  for comparison/studying its effect. In addition, for reservoirs with no injectivity, the technique may allow for the placement of the stimulation fluid facing the zone of interest within inflatable packer space  182  without direct injectivity. This may allow the stimulation fluid to start its chemical reaction of rock&#39;s enhancement that will lead to possible injectivity of the remaining stimulation fluid carried within fluid sampling and analysis system  100  for further enhancement. 
     Application of the stimulation fluids to subterranean formation  112  may allow for the simulation fluids to etch into subterranean formation  112 . Results from the application of stimulation fluids to subterranean formation  112  are illustrated in  FIGS.  4 A- 4 E .  FIGS.  4 A- 4 E  illustrate side views of different types of etching. For example,  FIG.  4 A  illustrates face dissolution which is considered as “acid wash” using limited volume of acid and low injection rate to clean the rock face and remove formation skin damage, it may also be caused by non-optimum acid concentration.  FIGS.  4 B to  4 D  illustrates different wormholes patterns which are depended on acid concentration, injection rate and ability of rapid rock reaction to the acid. Acid propagate depending on that from conical, dominated, to ramified wormholes in order illustrating the different possible shapes and efficiency.  FIG.  4 E  illustrates uniform dissolution which is a possible rock reaction at high injection rate of acid allowing low residence time which cause the rock to dissolve more uniformly.  FIG.  5 A- 5 E  are cross sections of each type of etching described above. During operations, conical wormhole in  FIG.  5 B  and dominant wormhole in  FIG.  5 C  may enhance sampling operations. 
       FIGS.  6 A and  6 B  illustrate a pre-job pressure-rate simulation taking into consideration the reservoir expected properties (or measured via open hole logs, caliper, corrosion, and cement image logs). In order to predict possible acid injection rates and pressure.  FIGS.  6 A and  6 B  may be used in conjunction with logs to design an acid for the stimulation fluid and concentration as well as predicting the type of wormhole to be created and the degree of reservoir enhancement. 
       FIG.  7 A  illustrate a schematic of packer assembly  204 . Illustrated schematically are inflatable packers  208   a  and  208   b  and channel  206 . As discussed above, stimulation fluid  70 ) moves through packer assembly  204  by traversing through channel  206 , where stimulation fluid  700  is redirected through one or more flow lines by one or more valves to exhaust port  218 . As illustrated in  FIG.  7 A , a case of minimum required injectivity is achievable while the upper part of the tool flow-line is completely isolated from the acid/mud through valve B.  FIG.  7 B  illustrates another example in which mud  702 , disposed between inflatable packers  208  through exhaust port  219 , is removed and replaced by stimulation fluid  700  through exhaust port  218 . This operation may be performed in case of no injectivity into the formation due to tightness by injecting the acid from storage tanks  236  (e.g., referring to  FIG.  2   ) through valve E. This may push mud  702  from the packed interval by opening valve B, allowing stimulation fluid  700  to face the formation by measuring the exact mud volume of replaced mud  702  by stimulation fluid  700  in order to start a chemical reaction and stimulation process. After a specific soaking period of stimulation fluid  700  within inflatable packer space  182 , valve B is closed, and an acid injection process starts similar to what is illustrated in  FIG.  7 A . In examples, the soaking period may range from thirty minutes to one hour or twenty minutes to an hour and a half. 
       FIG.  8    illustrates a flow chart  800  for performing a sampling operation in an ultra-tight formation. Flow chart  800  may begin with block  802 , in which fluid sampling tool  170  (e.g., referring to  FIGS.  1  and  3   ) is disposed in well  102  (e.g., referring to  FIGS.  1  and  2   ). In block  804 , a packer assembly  204  (e.g., referring to  FIG.  3   ) is positioned in a zone of interest. This may be performed by lowering fluid sampling tool  170  to an identified zone of interest that may be an ultra-tight formation. Additionally, within block  804 , inflatable packers  208  (e.g., referring to  FIG.  3   ) are activated to isolate the zone of interest. 
     After isolating as zone of interest in block  804 , a pressure draw down and pressure build up operation is performed in block  806 . A pressure draw down is performed using low-control pump-out section  210 , by dropping the pressure within inflatable packer inflatable packer space  182  using pump  212 . Next a pressure build is performed by stopping low-control pump-out section  210  and pump  212 , allowing the formation pressure to stabilize indicating reservoir pressure, flowing mobility and build up permeability. 
     Next, in block  808  an injectivity test is performed by using low-control pump-out section  210  and reversing the flow direction from draw-down to injection using pump  212 . This may increase the pressure in inflatable packer space  182  gradually with a controlled rate to explore the possible injectivity rate vs. pressure. 
     After an injectivity test is performed in block  808 , a direct stimulation fluid of stimulation fluid placement is performed in block  810 . The operation of applying the stimulation fluid to a formation is discussed above in  FIGS.  7 A and  7 B . After the placement of stimulation fluid in block  812  a soaking time for the stimulation fluid is run and monitoring of a pressure fall-off response is performed. Monitoring of pressure fall-off is performed at inflatable packer space  182  while the pressure is leaking off into a matrix until the pressure stabilizes and is recorded as the formation pressure. Specifically, the monitoring is performed by a sensor, identified in  FIGS.  7 A and  7 B  as “QGS1.” 
     In block  814  another pressure draw down is performed followed by a pressure build up. By performing pressure drawdown and build up before and after deployment of a stimulation fluid, the degree of reservoir enhancement may be found. This may be done by comparing flow pressure and rate before and after as well as the buildup mobility from both tests. Comparing the flow press and rate may be performed by look at the difference in the numbers before and after or by performing an advanced analytical solution for pressure derivative. Additionally, build up mobility may be found by the use of the Darcy equation (e.g., referring to Equation 1), or by utilizing as mentioned above, pressure transient analysis technique using the pressure derivative. 
     In block  816  a clean-up period is performed where flow from the formation is retrieved for a set time. In block  818 , during the clean-up period, hydrocarbon contamination of the fluid is measured. Once a minimum contamination level of hydrocarbons is met, a sampling process is performed in block  820 . It should be noted that flow chart  800  may then be repeated any number of times with any number of stimulation fluids. 
     Current technology does not include the systems and methods for a fluid sampling and analysis system  100  (e.g., referring to  FIG.  1   ) discussed above. Specifically, current technology does not utilize in situ stimulation followed by sampling technique. As discussed above, custom stimulation fluids may be utilized and even a mix of different types may be carried downhole to be tested in-situ for its improvement effects by performing Test-Inject-Test technique. Fluid sampling and analysis system  100 , as described above, may identify reservoir fluid type, locate fluid contacts, calculate formation fluid mobility based off the sample being extracted, collect representative reservoir fluid samples, analyze reservoir fluids in situ, and identify best stimulation treatment by performing in-situ testing for proposed fluids. For example, one or more types of stimulation fluids may be disposed in separate storage tanks  236 . These stimulation fluids may carry different acid type, concentrations, injection rate or volumes may give a diverse results which may be measured in real-time under in-situ conditions by utilizing test-inject-test methodology pin pointing the improvement degree at each combination recommending treatment for an identified reservoir/rock type in a formation. 
     Statement 1: A fluid sampling tool may comprise a packer assembly that includes one or more inflatable packers and one or more exhaust ports, a multi-chamber section that includes one or more sample chambers, at least two storage sections that each contain a storage tank, wherein each storage tank holds a stimulation fluid, and a channel that connects the packer assembly, the multi-chamber section, and the at least two storage sections. The system may further include a pump that is configured to move the stimulation fluid through the channel to the packer assembly and out the one or more exhaust ports. 
     Statement 2: The fluid sampling tool of statement 1, wherein each storage tank holds the stimulation fluid or a second stimulation fluid. 
     Statement 3: The fluid sampling tool of statements 1 or 2, wherein the stimulation fluid includes one or more inhibitors. 
     Statement 4: The fluid sampling tool of statements 1, 2 or 3, wherein the stimulation fluid etches at least one wormhole into a formation. 
     Statement 5: The fluid sampling tool of statements 1 or 2-4, wherein the stimulation fluid includes HCL, H2SO4, Alkaline Surfactant Polymers, or viscosity reducers. 
     Statement 6: The fluid sampling tool of statements 1 or 2-5, wherein the packer assembly is further configured to isolate a zone of interest with one or more inflatable packers. 
     Statement 7: The fluid sampling tool of statement 6, wherein the packer assembly is further configured to remove fluid from the zone of interest. 
     Statement 8: The fluid sampling tool of statement 7, wherein the packer assembly is further configured to add the stimulation fluid to the zone of interest. 
     Statement 9: The fluid sampling tool of statements 1 or 2-6, wherein the packer assembly is further configured to remove a fluid from a zone of interest. 
     Statement 10: The fluid sampling tool of statement 9, wherein the fluid is stored in the one or more sample chambers. 
     Statement 11: A method for performing a stimulation operation may comprise disposing a fluid sampling tool into a well, moving the fluid sampling tool to a zone of interest, isolating the zone of interest with a packer assembly on the fluid sampling tool, performing a first pressure draw down and a first pressure build up, and performing an injectivity test. The method may further comprise placing a stimulation fluid into the zone of interest, performing a section pressure draw down and a second pressure build up, and performing a sampling process. 
     Statement 12: The method of statement 11, further comprising performing a clean up period in which a fluid from a formation is captured by the fluid sampling tool. 
     Statement 13: The method of statement 12, further comprising measuring a hydrocarbon contamination level in the fluid. 
     Statement 14: The method of statements 11 or 12, further comprising comparing the first pressure draw down and the first pressure build up to the second pressure draw down and the second pressure build up to determine a reservoir enhancement from the stimulation fluid in the zone of interest. 
     Statement 15: The method of statements 11, 12, or 14, wherein the placing a stimulation fluid into the zone of interest includes moving the stimulation fluid from a storage tank within the fluid sampling tool to the zone of interest through the packer assembly. 
     Statement 16: The method of statement 15, wherein the stimulation fluid etches into a formation. 
     Statement 17: The method of statement 16, wherein the formation is an ultra-tight formation. 
     Statement 18: The method of statements 11 or 12-15, wherein the placing the stimulation fluid into the zone of interest is performed during a soaking time, wherein the soaking time is a time in which the stimulation fluid is exposed to a formation. 
     Statement 19: The method of statement 18, further comprising monitoring a pressure fall-off response during the soaking time. 
     Statement 20: The method of statements 11, 12-15, or 18, wherein the zone of interest is a tight formation. 
     The preceding description provides various embodiments of the systems and methods of use disclosed herein 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. It should be understood that the compositions and methods are described in terms of “including,” “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 element that it introduces. 
     For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite arrange not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. 
     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, and 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 of the 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 those embodiments. 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.