• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
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    • 专利摘要:
    METHOD FOR ASSESSING FLUID SAMPLE CONTAMINATION, AND, COMPUTER-READABLE MEDIA "A method for assessing fluid sample contamination is disclosed. A formation test tool is introduced into a well bore. The formation test tool comprises a Sensor data is acquired from the sensor and a contamination estimate is calculated.The remaining pumping time required to reach a contamination limit is then determined.
    公开号:BR112013019052B1
    申请号:R112013019052-3
    申请日:2012-01-24
    公开日:2020-07-21
    发明作者:Sami Abbas Eyuboglu；Mark Proett；Rohin Naveena Chandran；Anthony Herman Zuilekom；Li Gao
    申请人:Halliburton Energy Services, Inc.；
    IPC主号:
    专利说明:

    [0001] [0001] This application claims the benefit of Provisional Application US 61 / 437,501, which was deposited on January 28, 2011 and is hereby incorporated by the reference in its entirety. BACKGROUND OF THE INVENTION
    [0002] [0002] This description relates, in general, to the testing and evaluation of underground formation fluids and, more particularly, to methods and apparatus for assessing fluid sample contamination by the use of multiple sensors.
    [0003] [0003] To assess prospects for an underground hydrocarbon reserve, a representative sample of the reservoir fluid can be captured for detailed analysis. A sample of the formation fluids can be obtained by launching a sampling tool with a sampling chamber into the well hole in a vehicle, such as a profiling cable, steel cable, spiral pipe, articulated pipe or similar . When the sampling tool reaches the desired depth, one or more doors are opened to allow collection of the formation fluids. Doors can be operated in a variety of ways, such as by electrical, hydraulic or mechanical methods. Once the doors are opened, formation fluids move through the doors, and a sample of the formation fluids is collected in the sampling chamber of the sampling tool. After the sample has been collected, the sampling tool can be removed from the well bore, so that the sample of the formation fluid can be analyzed.
    [0004] [0004] Fluid analysis is possible using pumping formation testers that provide bottom measurements of certain fluid properties and enable the collection of a large number of representative samples stored in bottom conditions. Accurate determination of fluid properties and contamination during sampling with a pumping forming tester on a profiling cable is the primary objective for obtaining representative fluid samples with minimal drilling rig time. This is an important component of the formation assessment system established by the oil industry, especially for high profile and offshore wells. During drilling operations, a well hole is typically filled with a drilling fluid (“mud”), which can be water based or oil based. The mud is used as a lubricant and helps remove cuts from the borehole, but one of the most important functions of the mud is to control the well. Hydrocarbons contained in underground formations are contained in these formations at very high pressures. Predominant standard drilling techniques require that the hydrostatic pressure in the well bore exceeds the pressure of the formation, thereby preventing formation fluids from flowing uncontrollably into the well bore. The hydrostatic pressure at any point in the well bore depends on the height and density of the mud fluid column above this point. A certain hydrostatic pressure is desired in order to shift the pressure from the formation and prevent the fluid from flowing into the well. Thus, it is well known in the technology to control the density of the sludge, and it is often necessary to use “heavy” high-density sludge to achieve a desired hydrostatic pressure.
    [0005] [0005] When the hydrostatic pressure of the mud is greater than the pressure of the surrounding formation, the filtered drilling fluid will tend to penetrate the surrounding formation. Thus, the fluid in the formation near the well hole will be a mixture of filtered drilling fluid and formation fluid. The presence of the filtered fluid in the formation can interfere with attempts to sample and analyze the formation fluid. As a sample of fluid is extracted from the formation in the well hole wall, the first collected fluid may comprise primarily filtered drilling fluid, with the amount of filtrate in the mixture typically decreasing as the collected volume increases .
    [0006] [0006] Previous training test tools were designed to extract a fixed volume of fluid and carry this volume to the surface for analysis. It was soon realized that the fixed volume was not sufficient to collect a reasonable sample of the formation fluid because the sample was primarily filtered drilling fluid. To solve this problem, training test tools were developed that were able to continuously pump fluid into the test tool, so that sample collection can be controlled by the operator. Using these types of tools, operators try to avoid collecting filtrate from the fluid sample by pumping it for a period of time before collecting the fluid sample. Therefore, it is important to determine the quality of the fluid sample in situ, with the formation tester still in the well, in order to increase the efficiency and effectiveness of the sample collection. BRIEF DESCRIPTION OF THE DRAWINGS
    [0007] [0007] A more complete understanding of the present modalities and their advantages can be acquired by reference to the following description taken in conjunction with the attached drawings, in which equal reference numbers indicate equal resources.
    [0008] [0008] Figure 1 is a schematic cross-sectional representation of a test tool according to an exemplary embodiment of the present description.
    [0009] [0009] Figure 2 represents an example representation of a graphical representation of data of real density and adjustment data of the computer model that model the property of the fluid measured as a function of time according to certain modalities of the present description.
    [0010] [00010] Figure 3 represents an example display of an example contamination computer program in accordance with certain embodiments of the present description.
    [0011] [00011] Figure 4 represents example graphic representations created once data is loaded into the contamination computer program according to certain modalities of the present description.
    [0012] [00012] Figure 5 represents an example representation of the exemplary options for Sensor Type, Expected Fluid and Mud Type according to certain modalities of this description.
    [0013] [00013] Figure 6 represents an example representation of the results of the analysis of the exemplary contamination estimate when start and end are kept empty according to certain modalities of the present description.
    [0014] [00014] Figure 7 represents an example set to verify Signature of the Base Oil of Fluid Identification (FLID) according to certain modalities of the present description.
    [0015] [00015] Figure 8 represents a view of the results of the analysis of the example contamination estimate when the start and end times are selected according to certain modalities of the present description.
    [0016] [00016] Figure 9 represents a view of the sample results after an analysis of the contamination according to certain modalities of the present description.
    [0017] [00017] Figure 10 represents a view of a volume section instead of time according to certain modalities of the present description.
    [0018] [00018] Figure 11 represents a flow chart for an estimate of sample fluid and sample remaining pumping time according to certain embodiments of the present description.
    [0019] [00019] Although modalities of this description have been represented and described and are defined by reference to the exemplary modalities of the description, such references do not imply a limitation in the description, and no such limitation should be inferred. The subject in question is capable of considerable modification, alteration and equivalents in form and function, as will occur to those versed in the technique of the relevant technology and with the benefit of this description. The represented and described modalities of this description are examples only, and do not limit the scope of the description. DETAILED DESCRIPTION
    [0020] [00020] This description relates, in general, to the testing and evaluation of underground formation fluids and, more particularly, to methods and apparatus for assessing fluid sample contamination by the use of multiple sensors.
    [0021] [00021] For the purposes of this description, an information processing system can include any instrumentality or aggregate of operable instrumentalities to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record , reproduce, treat or use any form of information, intelligence, or data for business, scientific, control or other purposes. For example, an information processing system can be a personal computer, a networked storage device or any other suitable device, and can vary in size, shape, performance, functionality and price. The information processing system may include random access memory (RAM), one or more processing resources, such as a central processing unit (CPU) or hardware or software control logic, ROM and / or other types of memory non-volatile. Additional components of the information processing system may include one or more disk drives, one or more network ports for communicating with external devices as well as several input and output (I / O) devices, such as a keyboard, mouse and a video screen. The information processing system can also include one or more operable buses to transmit communications between the various hardware components.
    [0022] [00022] For the purposes of this description, computer-readable media may include any instrumentality or aggregate of instrumentalities that may retain data and / or instructions for a period of time. Computer-readable media may include, for example, without limitation, storage media, such as a direct access storage device (for example, a hard disk drive or floppy disk), a sequential access storage device (for example , a tape drive), compact disc, CD-ROM, DVD, RAM, ROM, exclusive electrically erasable programmable reading memory (EEPROM), and / or flash memory; as well as communications media such as wires, optical fibers, microwaves, radio waves, and other electromagnetic and / or optical carriers; and / or any combination of the above.
    [0023] [00023] Modes illustrative of the present description are described in detail below. In the interest of objectivity, not all features of an actual implementation are described in this specification. It is certainly realized that, in the development of any such real modality, numerous implementation-specific decisions must be made to achieve the specific objectives of the developers, such as compliance with system-related and business-related restrictions, which will vary from one implementation to one. another. Furthermore, it is clear that a development effort like this can be complex and time-consuming, but it will nevertheless be a routine undertaking for those skilled in the art with the benefit of this description.
    [0024] [00024] In underground well drilling and completion technology, certain tests can be performed on formations penetrated by a well bore. Such tests can be carried out in order to determine geological or other physical properties of the formation and the fluids contained therein. For example, parameters, such as permeability, porosity, fluid resistivity, temperature, pressure and saturation pressure, can be determined. These and other characteristics of the formation and the fluid it contains can be determined by conducting tests on the formation before the well is completed.
    [0025] [00025] To facilitate a better understanding of the present description, the following examples of certain modalities are given. In no way should the following examples be read to limit or scope the description. Certain modalities of the present description may be applicable to horizontal, vertical, bypassed or otherwise non-linear well holes in any type of underground formation. Certain modalities may apply to injection wells as well as production wells, including hydrocarbon wells. Certain modalities can be implemented, with a suitable tool for testing, retrieving and sampling over sections of the training. Certain modalities can be implemented with several samplers, which, for example, can be conducted through a flow passage in a tubular column or using a profiling cable, steel cable, spiral pipe, downhole robot or the like. Certain modalities can be used with a pumping formation tester on a profiling cable. Certain modalities may be suitable for use with a modular downhole formation test tool, such as the Halliburton Reservoir Description Tool (RDT), for example. Devices and methods according to certain modalities can be used in one or more of the profiling, measurement during drilling (MWD) and registration during drilling (LWD) operations. “Measurement during drilling” is the term for measuring bottom conditions in relation to the movement and location of the drilling assembly while drilling continues. “Record during drilling” is the term for similar techniques that focus more on measuring the formation parameter.
    [0026] [00026] Certain modalities according to the present description can enable not only an understanding of the cleaning behavior of the formation fluids, but also the quantitative determination of the fluid's qualities in real time. Certain modalities can highlight variables that play an important role in the direction and cleaning processes, while still providing characteristics of the trend of the level of contamination depending on both the time and the volume of fluid. Certain modalities may incorporate new fluid sensors to measure various fluid properties, including fluid density, resistivity, dielectric, viscosity and optical sensor data. In addition, each physical property sensor can be sensitive to different types of fluid, such as resistivity and dielectric, for contamination with water-based mud (“WBM”), and density and logarithmic mean T1 for contamination with water-based mud in oil (“OBM”). In this way, suitable physical sensors can be automatically selected to estimate fluid contamination. Multiple sensors can provide a better understanding of fluid flow and fluid type.
    [0027] [00027] Certain modalities may be especially relevant for improving reliability of fluid sample contamination and quality of the RDT sample in general, and for determining the remaining pumping time required to reach a target level of contamination. Certain modalities are especially pertinent to optimize the use time of the drilling platform by restricting an RDT pumping operation as soon as the fluid contamination satisfies the cleaning target, thereby increasing operational efficiency and increasing the quality of the sample. These and other technical advantages will be apparent to those skilled in the art in view of this description. Although numerous changes can be made by those skilled in the art, such changes are in the spirit of description.
    [0028] [00028] The precise determination of fluid properties and contamination during sampling with a pumping formation tester on a profiling cable, for example, is important in obtaining representative fluid samples from the reservoir with minimum drilling rig time. Despite the advances in fluid identification sensors, mixed-phase sampling, especially immiscible fluids, still represents a major challenge. Although apparent erratic sensor responses are often attributed to sensor noise, careful studies reveal that the sensors are really showing the true nature of multiphase fluid flow. However, it is difficult to determine the fluid type and contamination if the multiphase behavior of the fluid flow is not considered.
    [0029] [00029] The acquisition of high quality fluid samples in a WBM system and the determination of the level of contamination are straightforward in many cases. The same is not necessarily true for OBM systems, where the fluid properties and / or phase behavior of the hydrocarbon can be changed because two fluids are miscible. Experimental results indicate that samples contaminated with OBM filtrate may have lower boiling point pressures and greater fluid fractions. Although corrections can be applied to compensate for contamination, the conventional contamination limits for accurate analysis are 5% for oils, and 2% for condensates. Condensed gas systems are more sensitive than oils and, in some cases, can be converted to oil-equivalent systems. Fluid samples taken may have very low levels of contamination in order to produce PVT properties that are representative of uncontaminated hydrocarbons. A training tester can contain one or more modules that allow the real-time estimation of contamination levels.
    [0030] [00030] Figure 1 illustrates a schematic cross-sectional representation of a test tool 100 that can be used with certain embodiments of the present description. The training test tool 100 may be suitable for testing, retrieving and sampling across sections of a training. The test tool 100 can include several modules (sections) capable of carrying out various functions. For example, as shown in figure 1, test tool 100 may include a hydraulic power module 105 that converts electrical energy to hydraulic energy; a probe module 110 for taking samples of the formation fluids; a flow control module 115 for regulating the flow of various fluids in and out of tool 100; a fluid test module 120 for performing different tests on a fluid sample; a multi-chamber sample collection module 125 that can contain various chamber sizes for storing collected fluid samples; a telemetry module 130 that provides electrical and data communication between modules and a wellhead control unit (not shown) and possibly other sections designated in figure 1 collectively as 135. The arrangement of the various modules, and additional modules, may depend on the specific application, and is not considered here.
    [0031] [00031] More specifically, telemetry module 130 can condition power to the remaining sections of test tool 100. Each section can have its own process control system and can function independently. Telemetry module 130 can provide a common intra-tool power bus, and the entire tool column (possible extensions beyond test tool 100 not shown) can share a common communication bus that is compatible with other logging tools. This arrangement can enable the tool to be combined with other registration systems.
    [0032] [00032] The forming test tool 100 can be conducted in a borehole by profiling cable (not shown), which may contain conductors to conduct energy to the various components of the tool and conductors or cables (coaxial or fiber optic cables) ) to provide bidirectional data communication between tool 100 and a wellhead control unit (not shown). Preferably, the control unit includes a computer and associated memory to store programs and data. The control unit can generally control the operation of tool 100 and process data received from it during operations. The control unit can have a variety of associated peripherals, such as a recorder to record data, a screen to display desired information, printers and others. The use of the control unit, the screen and the recorder is known in well logging technology and is therefore not further discussed. In an exemplary embodiment, the telemetry module 130 can provide both electrical and data communication between the modules and the wellhead control unit. In particular, the telemetry module 130 can provide a high-speed data bus from the control unit to the modules to transfer sensor readings and load control instructions that start or end various test cycles and adjust different parameters, such as rates in which several pumps are operating.
    [0033] [00033] The flow control module 115 of the tool can include a pump 155, which can be a double-acting piston pump, for example. The pump 155 can control the flow of the formation-forming fluid to the flow line 140 by means of one or more probes 145A and 145B. The number of probes may vary depending on the implementation. Fluid entering probes 145A and 145B can flow through flow line 140 and can be discharged into the well bore via exhaust 150. A fluid control device, such as a control valve, can be connected to the flow line 140 to control the flow of fluid from flow line 140 into the borehole. The fluids in the flow line can be pumped either up or down, with all the fluid in the flow line directed into or through the pump 155.
    [0034] [00034] The fluid test section 120 of the tool may contain a fluid test device, which analyzes the fluid flowing through the flow line 140. For the purpose of this description, any suitable device or devices can be used to analyze the fluid. For example, the Halliburton Memory Recorder quartz meter holder can be used. In this quartz meter, the pressure resonator, temperature compensation and reference crystal are packaged as a single unit, with each adjacent crystal in direct contact. The set is contained in an oil bath that is hydraulically coupled to the pressure being measured. The quartz meter enables the measurement of such parameters as the pressure drop of the fluid being extracted and the temperature of the fluid. Furthermore, if two fluid test devices 122 are performed in tandem, the pressure difference between them can be used to determine the viscosity of the fluid during pumping or the density when the flow is stopped.
    [0035] [00035] The sample collection module 125 of the tool can contain one or more chambers 126 of various sizes for storing the collected fluid sample. A collection chamber 126 may have a piston system 128 that divides chamber 126 into a top of chamber 126A and a base of chamber 126B. A conduit can be coupled to the base of the chamber 126B to provide fluid communication between the base of the chamber 126B and the external environment, such as the well bore. A fluid flow control device, such as an electrically controlled valve, can be placed in the conduit to selectively open it to allow fluid communication between the base of chamber 126B and the well bore. Similarly, chamber section 126 may also contain a fluid flow control device, such as an electrically operated control valve, which is selectively opened and closed to direct fluid from the formation of flow line 140 into the chamber. higher than 126A.
    [0036] [00036] Probe module 110 can, in general, allow recovery and sampling of formation fluids in sections of a formation along the longitudinal geometric axis of the borehole. The probe module 110 and, more particularly, the sealing block, may include electrical and mechanical components that facilitate the testing, sampling and recovery of the formation fluids. As is known in the art, the sealing block is the part of the tool or instrument in contact with the formation or specimen of the formation. A probe can be provided with at least one elongated seal block which provides seal contact with a borehole surface at a desired location. Through one or more slits, fluid flow channel or recesses in the sealing block, fluids from the sealed part of the formation surface can be collected in the tester via the probe's fluid path.
    [0037] [00037] In the illustrated modality, one or more adjustment rims (shown as 160A and 160B) can be located, in general, opposite the tool probes 145A and 145B. Ram 160A and 160B can be moved laterally by actuators placed inside probe module 110 to extend away from the tool. Pre-test pump 165 can be used to perform pre-tests on small volumes of formation fluid. Probes 145A and 145B can have pressure transducers with a high-resolution, temperature-compensated voltage meter (not shown) that can be isolated with shut-off valves to monitor the probe pressure independently. Pre-test piston pump 165 can have a pressure transducer with a high resolution voltage meter, which can be isolated from the intra-tool flow line 140 and from probes 145A and 145B. Finally, the module can include a resistance cell, optics or other cell type (not shown) located near probes 145A and 145B to monitor fluid properties immediately after entering each probe.
    [0038] [00038] In relation to the exposed discussion, the formation test tool 100 can be operated, for example, in a profiling cable application, in which the tool 100 is guided to the inside of the bore hole by means of the profiling to a desired location (“depth”). The hydraulic tool system can be implemented to extend one or more ram 160A and 160B and seal block (s) that include one or more probes 145A and 145B, thereby creating a hydraulic seal between the seal block and the wall of the borehole in the area of interest. To collect fluid samples in the condition in which such fluid is present in the formation, the area close to the seal block (s) can be discharged or pumped. The pumping rate of piston pump 155 can be regulated in such a way that the pressure in the flow line 140 near the seal block (s) is maintained above a particular fluid sample pressure. Thus, while piston pump 155 is operating, fluid tester 122 can measure fluid properties. Device 122 can provide information about the contents of the fluid and the presence of any gas bubbles in the fluid to the surface control unit. By monitoring the gas bubbles in the fluid, the flow in flow line 140 can be constantly adjusted to maintain a single phase fluid in flow line 140. These fluid properties and other parameters, such as pressure and temperature, can be used to monitor fluid flow while the formation fluid is being pumped for sample collection. When it is determined that the formation fluid flowing through the flow line 140 is representative of the conditions in situ, the fluid can then be collected in the fluid chamber (s) 126.
    [0039] [00039] When tool 100 is driven into the borehole, the borehole fluid may enter the lower section of fluid chamber 126B. This can cause piston 128 to move inward, filling the base of chamber 126B with fluid from the borehole. This may be due to the hydrostatic pressure in the conduit connecting the base of chamber 126B and a borehole being greater than the pressure in flow line 140. Alternatively, the conduit can be closed by an electrically controlled valve, and it can be allowed that the base of chamber 126B is filled with fluid from the borehole after tool 100 is positioned in the borehole. To collect the formation fluid in chamber 126, the valve connecting the base of chamber 126B and flow line 140 can be opened and piston pump 155 can be operated to pump formation fluid into the flow line. 140 through the inlets of the sealing block (s). As the piston pump 155 continues to operate, the flow line pressure may continue to rise. When the flow line pressure exceeds the hydrostatic pressure (pressure at the bottom of chamber 126B), the formation fluid may begin to fill at the top of chamber 126A. When the upper chamber 126A has been filled to a desired level, the valves connecting the chamber with both flow line 140 and the borehole can be closed, which can ensure that the pressure in chamber 126 remains at the pressure in the which fluid was collected ah.
    [0040] [00040] An approach to estimating contamination levels in real time is based on the optical properties of fluids entering the tester. The technique basically uses the differences in the absorption spectrum (color contrast) between the OBM contaminant and the formation fluid to unroll the spectrum from a fluid measurement. Optical sensors measure the optical density of the flowing fluid and use empirical relationships to transform the optical density into contamination data by determining the composition of the absorbed light spectrum measured from the sample. Depending on this absorption spectrum, one can estimate the types of materials present in the fluid and the proportion of each material in the fluid. A problem with optical analysis is that the measured property is considered to be directly linked to contamination and may not necessarily be the case.
    [0041] [00041] Another approach to estimate contamination is to use electrical resistivity which is based on the measurement of the apparent resistivity of fluids entering the tool. The MRILab Fluid Analyzer, available through Halliburton, in combination with RDT, can offer an alternative based on the properties of Fluid Nuclear Magnetic Resonance (NMR). The other property of the fluid is the density of the fluid to assess the quality of a sample of fluid at the bottom of the well while monitoring a fluid property over time.
    [0042] [00042] A high resolution fluid density sensor can quickly and reliably monitor the frequency change of a vibrating tube immersed in the fluid sample. A vibrating tube density sensor can operate under the physical premise that its resonant frequency is directly related to the fluid density in the tube. In reality, however, because of its high sensitivity, the sensor response is influenced by multiple factors, including temperature, pressure and specific mechanical design configuration of the sensor.
    [0043] [00043] Using a density sensor, the density of the fluid is measured at the bottom of the well and the measured density is plotted against time. As time increases, the measured density of the fluid in the sample volume changes until it levels very close to the formation fluid density. This density leveling is known as asymptotic convergence and the density value at this point is the asymptotic value. It is usually preferred to acquire a sample of the formation fluid when the measured properties of the fluid sample reach asymptotic levels, which indicates that the amount of filtration in the sample cannot be further reduced. The difficulty with this method is that, although a balance between the amounts of formation fluid and filtered drilling fluid entering the sample volume has been achieved, the level of contamination in the fluid mixture may not yet be known. Therefore, using multiple sensors (logarithmic mean T1, viscosity index, etc.) during the contamination estimate will allow a better understanding of fluid flow and fluid type. The easy visual interpretation of T1 domain when changes are observed in T1 distributions as a function of pumping time makes an advantage of the contamination estimate. The change in fluids can be visually detectable, ranging from mud filtrate to oil, through a range of experiments. The relation used to transform logarithmic mean T1 into viscosity η in the contamination estimation algorithm is given by
    [0044] [00044] In certain modalities, contamination can be estimated as a function of time. An important feature of any contamination algorithm is the ability to estimate the Contamination Index (CI) at a given time and to predict the additional time needed to reach a certain limit. This requirement brings the dimension of time to the problem. In certain exemplary modalities, a contamination algorithm can have two parts: (1) a time function that describes the behavior of the fluid property (density, viscosity index or logarithmic mean T1) as a function of time; and (2) a mixing model that can estimate the volume fractions of two fluids given any information on fluid properties. In certain exemplary embodiments, the following functions can model the fluid properties measured as a function of time
    [0045] [00045] Figure 2 represents an example representation 200 of a graphical representation of density data in real time and adjustment data of the computer model that model the property of the fluid measured as a function of time according to certain modalities of the present description. . Real-time density data is shown on line 205. Computer model adjustment data is shown on dashed line 210.
    [0046] [00046] In certain exemplary modalities, when v1 and v2 are determined from the data adjustment, they can be used to compute the volumetric saturation of the contaminant in each experiment. For this purpose, consider five mixing models. All of them refer to the data values of the fluid mixture f (t) up to the data values at the end point v1 and v2, given their respective saturations s1 = CI and s2 = 1 - CI
    [0047] [00047] Thus, certain modalities may include one or more of the steps of: reading data in real time; in the manner of the minimum square, adapt f (t) to a parameterized function of a given structure (data in real time); compute the adjustment of the minimum square of the contaminant: v1 = f (t = 0), and of the formation fluid: v2 = f (t = ∞); and compute the contamination index by applying a fluid mixing model using v1, v2 and f.
    [0048] [00048] Certain embodiments in accordance with the present description may include a contamination program in real time that incorporates contamination algorithms and fluid sensor data, such as fluid density, resistivity, dielectric, viscosity and optical sensor data. Numerical and analytical models may be able to measure and describe the cleaning behavior of the formation fluids and their qualities, thus accessing a well-bottomed fluid contamination content by drilling filtered fluid using sensors from the recording tools. Each physical property sensor can be sensitive to different types of fluid, such as resistivity and dielectric, for WBM contamination, and density and logarithmic mean T1 for OBM contamination. The contamination program can automatically select suitable physical sensors to estimate fluid contamination. Multiple sensors will allow a better understanding of the fluid flow and the type of fluid. Certain modalities can be implemented with the INSITE® data acquisition program available through Halliburton.
    [0049] [00049] Figure 3 represents an example display 300 of an example contamination assessment computer program in accordance with certain embodiments of the present description. To load the data into the exemplary contamination assessment program shown in figure 3, the Input_adi button can be used to reach a database structure with the corresponding data. Figure 4 represents an example display 400 of the exemplary graphic representations created once data is loaded into the contamination computer program in accordance with certain embodiments of the present description. Thus, in certain exemplary modalities, after data can be selected and transferred, eighteen graphic representations can be represented on a computer screen, as illustrated by the non-limiting example in figure 4. It should be noted that figure 4 is merely an example, and any suitable number and variation of graphical representations can be employed. Graphical representations can serve as a check on the quality of work before starting contamination analysis. Graphical representations can help a user to identify the nature of the data readings obtained during work and can help the user decide which data will be most useful in carrying out a particular contamination analysis. Exemplary names of the data in each graphical representation are shown in Table 1.
    [0050] [00050] Figure 5 represents an example representation 500 of the exemplary options of Sensor Type, Expected Fluid and Mud Type according to certain modalities of the present description. Sensor Type options can provide the user with different data (for example, Density, logarithmic mean T1, Viscosity Index, Capacitance, Hydrogen Index, Resistivity, Mobility Index, Reference Density, Density_Flidl_FSS, Density_Flidl_FSS) that can be used to estimate the level of contamination of the fluid in the formation. In certain exemplary modalities, the expected fluid (oil, gas and water from the formation) and the type of mud (OBM or WBM) can also be selected before starting the contamination estimate.
    [0051] [00051] In certain exemplary modalities, the start and end times can be selected as the start and end points of the contamination analysis. If these times are kept empty, the start time is zero and the end time is the last time data is recorded. Start time is the time of the filtrate density shown on the sensor. If the filtrate density is known, the start time can be implemented in the program and, therefore, more accurate contamination estimate can be calculated.
    [0052] [00052] Figure 6 represents an example 600 representation of the results of the analysis of the exemplary contamination estimate when start and end are kept empty according to certain modalities of the present description. In figure 6, the top panel (A) shows the data that can be used to estimate contamination as a function of time. In this exemplary modality, density data can be used for the test. Line 605 can be real time (density) and dotted line 610 can be data suitable for the computer. The middle panel (B) can be the results of contamination as a function of time. Line 615 can be the contamination estimate for data suitable for the computer. Line 620 can be the contamination estimate for actual data. Line 625 can be the “mobile filter” developed for the green curve. The base panel (C) is an enlarged view of the middle panel from 0 to 20%. However, if the filtrate is known, start and end times can be entered to calculate a more accurate contamination estimate.
    [0053] [00053] In certain embodiments, a pre-work method can be used to estimate the density of the base oil before work. In a certain exemplary modality, a pre-work method can be used when sampling oil / synthetic based types of mud. These methods, discussed in further detail below, can be used with the set 700 of figure 7, for example.
    [0054] [00054] Figure 7 represents an example set 700 for verifying a fluid identification base oil signature (FLID) according to certain modalities of the present description. Assembly 700 may include a FLID tool 705, which may include one or more of a pressure sensor 710, a temperature sensor 715, a density sensor 720, a resistivity sensor 725, a temperature sensor 730 and a temperature sensor. capacitance 735 coupled in a flow line 706. The set 700 can be used to verify the signature of the base oil through the FLID 705 tool to determine readings of the density, resistivity and capacitance sensors at the surface temperature and at a specified pressure . This check can be carried out at the well site with a sample of base oil used during a recent circulation. Assembly 700 can be connected using a crossover of electronic components and flow line 740 at the top and a section of terminator 745, such as a standard RDT plug terminator at the base, for example. Base oil can be stored in any suitable container 750 and pumped into the 705 tool, for example, with a 755 high pressure air driven pump. Initially, air can be circulated through the 705 tool to obtain an air signature. The base oil can then flow through the 705 tool to a specific pressure. Once the flowing signature is obtained, obstructions 760 and 765 at the inlet and exhaust, respectively, of the tool can be closed to obtain a static reading under pressure. Both fluid and static readings can then be used as an input for analysis of contamination at the bottom of the well in real time.
    [0055] [00055] In a certain exemplary mode, a pre-work procedure can be as follows: (1) connect the FLID 705 tool at intersection 740 and plug 745, for example, as shown in figure 7; (2) energize the FLID 705 tool and start a station registration; (3) with the pump 755 exposed to the air, open the intake and exhaust obstructions 760, 765 and circulate the air through the assembly 700; (4) immerse the pump 755 in the base oil container 750 and establish the flow of the base oil through tool 705; (5) while monitoring the pressure sensor 710 in the assembly 700, check the exhaust obstruction 765 to achieve a desired pressure; (6) maintain pressure long enough to record readings under flow conditions; (7) close the 760 intake obstruction and maintain pressure to obtain readings under static conditions; (8) open the intake and exhaust obstructions 760, 765 and remove the pump 755 from the base oil, circulate air through the assembly 700; (9) interrupt the station registration and de-energize the FLID 705; (10) disconnect all connections and prepare the set 700 to be executed inside the well hole. Any suitable power source can be used, including battery, generator or other power source, depending on the design and implementation needs.
    [0056] [00056] Figure 8 represents a view of the results of the analysis of the contamination estimate of example 800 when the start and end times are selected according to certain modalities of the present description. In the results of the analysis of the contamination estimate 800, exemplary start and end times of 39.1 and 520 min are used. A difference between figures 6 and 8 is that, in the top panel of figure 8, line 805 shows the actual data (density) between the selected start and end times, and the contamination line 810 is represented between the start times. beginning and end.
    [0057] [00057] Figure 9 represents a view of the results of example 900 after an analysis of the contamination according to certain modalities of the present description. Figure 9 shows the filtrate and the density of the clean fluid calculated by the computer using mathematical models, and these values are used in the contamination estimate. In this example, 0.78 g / cc and 0.67 g / cc are the filtrate and clean fluid values that the contamination computer program calculated, respectively. Estimates of the contamination result for adequate data (line 810) comprise 4.6% and for real data line 805 it is 5.7%. To achieve the desired 4.0% of contamination, 79.61 more pumping minutes may need to be performed. Knowing the precise remaining pumping time can help determine whether to continue pumping or taking the sample.
    [0058] [00058] Figure 10 represents a view of a section of volume 1000 instead of time according to certain modalities of the present description. In certain modalities, the user may have the option to analyze the contamination estimate according to the accumulated volume and the corrected accumulated volume, as seen in figure 10. However, although certain examples here consider estimate values based on volume , it is understood that the contamination estimate can be converted from volume-based to weight-based.
    [0059] [00059] Figure 11 represents a flowchart for an example 1100 method of estimating fluid sample and remaining pumping time according to certain embodiments of the present description. Precepts of the present description can be used in a variety of implementations. As such, the order of the steps that comprise the 1100 method may depend on the chosen implementation.
    [0060] [00060] Methods and apparatus according to certain modalities of the present description can be effective to estimate the contamination of fluid sample and the remaining pumping time. In certain embodiments, suitable physical sensors can be automatically selected to estimate fluid contamination. Multiple sensors can provide a better understanding of fluid flow and fluid type. Furthermore, knowledge of the filtrate density before work will help to calculate the most accurate contamination estimate. Knowledge of the precise remaining pumping time will help a user to decide whether to continue pumping or to take the sample. Certain modalities can be implemented in any type of mud. Certain modalities of the present description may use a vibrating tube density sensor that enables highly accurate and repetitive measurements of fluid density at the bottom of the well and provides an accurate contamination estimate. Certain modalities may be more accurate by allowing the density of the filtrate to be known before work, which will help to calculate a more accurate contamination estimate.
    [0061] [00061] Therefore, the present description is adapted to the well to achieve the mentioned purposes and advantages, as well as those that are inherent. The particular modalities previously disclosed are only illustrative, since the present description can be modified and practiced in different but equivalent ways, apparent to those versed in the technique with the benefit of the precepts here exposed. Furthermore, no limitation is intended to the details of construction or design shown here, other than those described in the following claims. Therefore, it is evident that the particular illustrative modalities previously disclosed can be altered or modified, and all such variations are considered in the scope and spirit of the present description. Also, the terms in the claims have their simple ordinary meanings, unless otherwise explicitly and clearly defined by the patent holder.
    权利要求:
    Claims (15)
    [0001]
    Method for assessing contamination of a fluid sample, characterized by the fact that it comprises: introducing a forming test tool (100) into a well bore, where the forming test tool comprises multiple sensors; automatically selecting a sensor from said multiple sensors to estimate fluid contamination; acquire sensor data from the selected sensor; calculate a contamination estimate; and determine the remaining pumping time required to reach a contamination limit
    [0002]
    Method for assessing contamination of a fluid sample according to claim 1, characterized by the fact that it additionally comprises: determine if a contamination limit has been reached.
    [0003]
    Method for assessing contamination of a fluid sample according to claim 2, characterized by the fact that it additionally comprises: take a fluid sample if the contamination limit has been reached; and / or restrict a pumping operation after the contamination limit has been reached based, at least in part, on the contamination estimate; and / or restrict a pumping operation after the contamination limit has been reached based, at least in part, on the remaining pumping time.
    [0004]
    Method for assessing contamination of a fluid sample according to any one of claims 1 to 3, characterized by the fact that the contamination estimate is a function of time.
    [0005]
    Method for assessing contamination of a fluid sample according to any one of claims 1 to 4, characterized in that the sensor data is acquired in real time.
    [0006]
    Method for assessing fluid sample contamination according to any one of claims 1 to 5, characterized in that the sensor data comprises one or more of the fluid density data, resistivity data, dielectric data, viscosity data and optical sensor data.
    [0007]
    Method for assessing fluid sample contamination according to any one of claims 1 to 6, characterized in that the sensor is sensitive to a plurality of fluid types.
    [0008]
    Method for assessing fluid sample contamination according to any one of claims 1 to 7, characterized in that it additionally comprises: take sensor readings from a base oil, where the sensor readings indicate a base oil property; and where the contamination estimate is based, at least in part, on the ownership of the base oil.
    [0009]
    Non-transitory, tangible, computer-readable media with executable instructions stored within it to assess fluid sample contamination, using the method as defined in claim 1, the readable media being characterized by the fact that the executable instructions cause a processor to: automatically select a sensor from a formation test tool (100) having multiple sensors inserted into a well hole to calculate a contamination estimate; read sensor data acquired through the selected sensor; calculate the contamination estimate; and determine the remaining pumping time required to reach a contamination limit.
    [0010]
    Non-transitory tangible computer-readable media according to claim 9, characterized by the fact that the contamination estimate is a function of time.
    [0011]
    Non-transitory tangible computer-readable media according to either of claims 9 or 10, characterized by the fact that the sensor data is read in real time.
    [0012]
    Non-transitory, tangible computer-readable media according to any of claims 9 to 11, characterized in that the sensor data comprises one or more of the fluid density data, resistivity data, dielectric data, viscosity and optical sensor data.
    [0013]
    Non-transitory tangible computer-readable media according to any of claims 9 to 12, characterized by the fact that executable instructions additionally cause the computer to: read sensor data corresponding to a base oil, where the sensor data corresponding to a base oil indicates a property of the base oil; and where the contamination estimate is based, at least in part, on the ownership of the base oil.
    [0014]
    Non-transitory tangible computer-readable media according to any of claims 9 to 13, characterized by the fact that the calculation of the contamination estimate comprises the computation of a contamination index, and, optionally, in which the computation of the contamination index it is based, at least in part, on a mixing model.
    [0015]
    Non-transitory tangible computer-readable media according to any of claims 9 to 14, characterized by the fact that the contamination estimate is based, at least in part, on one or more of a regression and statistical analysis.
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    同族专利:
    公开号 | 公开日
    AU2012209236B2|2015-11-05|
    EP2668370B1|2014-12-10|
    CA2825177A1|2012-08-02|
    BR112013019052A2|2017-03-28|
    WO2012103069A3|2013-05-23|
    US20130311099A1|2013-11-21|
    WO2012103069A2|2012-08-02|
    EP2668370A2|2013-12-04|
    CA2825177C|2016-07-19|
    MX2013008703A|2014-07-30|
    MX337924B|2016-03-28|
    US10280745B2|2019-05-07|
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    法律状态:
    2018-12-18| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|
    2019-10-22| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|
    2020-06-02| B09A| Decision: intention to grant|
    2020-07-21| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 24/01/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
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    US201161437501P| true| 2011-01-28|2011-01-28|
    US61/437501|2011-01-28|
    PCT/US2012/022330|WO2012103069A2|2011-01-28|2012-01-24|Method and apparatus for evaluating fluid sample contamination by using multi sensors|
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