X-ray fluorescence measurement of multi-phase oilfield fluids

Abstract

A method for estimating an elemental composition of a multi-phase oilfield fluid includes: obtaining a sample of the multi-phase oilfield fluid; stirring the sample with a viscosity modifier to convert the sample into a high viscosity paste; introducing the high viscosity paste into a chamber of an XRF device; performing XRF measurement on the high-viscosity paste by using an XRF device; and evaluating the XRF measurements to estimate the elemental composition of the obtained multiphase oilfield fluid.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] none Technical Field

[0003] The present application relates to x-ray fluorescence (XRF) measurements, and more particularly to XRF measurements of multiphase oilfield fluids. Background Art

[0004] When drilling a well for the production of hydrocarbons, a drilling fluid is typically circulated in the well for a variety of purposes. For example, the drilling fluid is typically used to provide downhole hydrostatic pressure to counteract the subsurface formation pressure, to cool and lubricate the drill bit, to flush drill cuttings from the drill bit and bring them to the surface through the wellbore annulus, and to provide hydraulic power for various downhole tools. The returning drilling fluid is typically examined at the surface to evaluate its properties and various properties of the formation surrounding the well.

[0005] As known to those of ordinary skill, drilling fluids are highly complex multiphase fluids, typically including at least one liquid phase and one or more solid phase components. The liquid phase can be a thickened aqueous solution of a polymer or clay in a brine of a water-based drilling fluid (WBM), an emulsion of an aqueous fluid, such as a brine dispersed in an oil or diesel continuous phase of an oil-based drilling fluid (OBM), or a brine dispersed in a synthetic oil-based drilling fluid (SBM) when the continuous phase is a synthetic oil, or an emulsion (commonly referred to as a direct emulsion drilling fluid) of oil or diesel dispersed in an aqueous fluid such as brine. In use, drilling fluids typically also include drill cuttings and fine particulate matter from the drilled formation. Monitoring the changes in the composition of the drilling fluid is important for predicting the performance of the drilling fluid and understanding the properties of the drilled formation.

[0006] X-ray fluorescence (XRF) spectroscopy is a well-known technique for measuring the elemental composition of a sample. For example, XRF is commonly used in oilfield applications to evaluate drill cuttings samples and determine the elemental composition of formation rocks. XRF measurements have also been proposed for evaluating drilling fluids, however, one difficulty with using XRF to evaluate drilling fluids is that drilling fluids typically settle and undergo phase separation on the time scale of the XRF measurement. This can lead to inaccurate and unreliable measurements. There remains a need for improved methods for measuring the elemental composition of in-use drilling fluids. Summary of the invention

[0007] none BRIEF DESCRIPTION OF THE DRAWINGS

[0008] For a more complete understanding of the disclosed subject matter and advantages thereof, reference is now made to the following description taken in conjunction with the accompanying drawings, in which:

[0009] Figure 1An example drilling rig is depicted that includes a system for performing XRF measurements of a drilling fluid in use during drilling operations.

[0010] Figure 2 A flow chart depicts an example method for estimating elemental composition of a multiphase drilling fluid used in a wellbore drilling operation.

[0011] Figure 3 An example embodiment of an XRF measurement system for performing XRF measurements on a drilling fluid used during drilling operations is depicted.

[0012] Figure 4A and 4B (collectively, FIG. 4 ) depicts portions of a measured XRF spectrum (XRF measurement) obtained from a drilling fluid sample ( 4A) and from a paste sample ( 4B) obtained by blending the drilling fluid sample with carbon black.

[0013] Figure 5 Plotted are the barium peak height versus time (in minutes) for four enhanced viscosity drilling fluids.

[0014] Fig. 6A and 6B (collectively, FIG. 6 ) depicts a portion of a measured XRF spectrum (XRF Measurement) obtained from a paste sample comprising a drilling fluid and carbon black mixture, showing the barium peak ( 6A ) and the silicon peak ( 6B ).

[0015] Figure 7 A process diagram of an exemplary dewatering process including high gravity solids recovery and low gravity solids removal of an exemplary drilling fluid is depicted.

[0016] Figure 8 Depicted is a graph of volume percent of LGS on the vertical axis versus volume percent of HGS on the horizontal axis for an example dehydration operation. DETAILED DESCRIPTION

[0017] Embodiments of the present disclosure include methods and systems for estimating the elemental composition of a multiphase oilfield fluid. In an example embodiment, a method includes obtaining a sample of the multiphase oilfield fluid; stirring the sample with a viscosity modifier to convert the sample into a high viscosity paste; introducing the high viscosity paste into a chamber of an XRF device; performing an XRF measurement of the high viscosity paste using the XRF device; and evaluating the XRF measurement to estimate the elemental composition of the obtained multiphase oilfield fluid.

[0018] Figure 1An example drilling rig 20 is depicted that includes a system 150 for performing XRF measurements of drilling fluids in use during drilling operations. The drilling rig 20 may be positioned above a subsurface formation (not shown). The drilling rig may include, for example, a derrick and a hoisting device (also not shown) for raising and lowering a drill string 30 that extends into a wellbore 40, as shown, and includes, for example, a drill bit 32 and one or more downhole measurement tools 38 (e.g., logging while drilling tools or measurement while drilling tools). Suitable drilling systems, including, for example, drilling, steering, logging, and other downhole tools, are well known in the art.

[0019] The drilling rig 20 also includes a surface system 50 for controlling the flow (or circulation) of a drilling fluid 35 used on the drilling rig (e.g., used in drilling the wellbore 40). In the example drilling rig shown, the drilling fluid 35 is pumped downhole (as shown at 62) by a conventional mud pump 57. The drilling fluid 35 can be pumped along a path to the drill string 30, such as through a standpipe 58 and a mud hose 59. The drilling fluid 35 is typically discharged from the drill string 30 at or near the drill bit 32 (e.g., by a drill bit jet) and produces an upward mud flow 64 through the wellbore annulus 42 (the annular space between the drill string and the wellbore wall). The drilling fluid 35 then flows to a mud pit 56 (or a mud pit system including a plurality of mud pits) through a return conduit 52 and a solids control device 55 (e.g., a shale shaker). It should be understood that the terms drilling fluid and mud are used synonymously herein.

[0020] The circulating drilling fluid 35 is intended to perform many functions while drilling, one of which is to carry drill cuttings to the surface (in the upward flow 64). The drill cuttings are typically removed from the returning mud by a shale shaker 55 (or other similar solids control device) in the return conduit (e.g., directly upstream of the mud pit 56). The drilling fluid 35 is typically reused and recirculated downhole. Formation gases released during the drilling process may also migrate to the surface in the circulating drilling fluid. These gases are typically removed from the fluid, for example, via a degasser or gas trap 54 located in or near a header tank 53, which in the exemplary description is directly upstream of the shale shaker 55. The drill cuttings and gases are typically examined at the surface to evaluate the formation through which the wellbore has been drilled.

[0021] The drilling rig 20 also includes a system 150 for performing XRF measurements on drilling fluids used during drilling operations. The system 150 can be deployed at substantially any single location or multiple locations in the surface system 50, for example, along the return conduit 52, as depicted between the shale shaker 55 and the mud pit 56, in fluid communication with the mud pit 56, or along the standpipe 58 or mud hose 59. The disclosed embodiments are not limited in this regard. As described below with respect to Figure 2 and Figure 3 As described in more detail, the system 150 may be configured to receive a drilling fluid sample, prepare the sample for XRF evaluation, and perform XRF measurements on the prepared sample.

[0022] Although Figure 1 A land drilling rig 20 is depicted, but it should be understood that the disclosed embodiments are equally applicable to land drilling rigs or offshore drilling rigs. As known to those of ordinary skill, an offshore drilling rig typically includes a platform deployed on top of a riser extending from the seafloor to the surface of the water. The drill string extends downward from the platform, through the riser, and into the wellbore through a blowout preventer (BOP) located on the seafloor. The disclosed embodiments are not limited in these respects.

[0023] Figure 2 A flow chart of an example method 100 for estimating the elemental composition of a multiphase oilfield fluid used in a wellbore drilling or completion operation is depicted. The method includes receiving (or obtaining) a sample of the oilfield fluid at 102. The sample may include a drilling fluid sample obtained from substantially any location in the surface system 50, for example, from a return conduit 52, a shale shaker 55, a mud pit 56, a standpipe 58, or a mud hose 59 ( Figure 1 ) or an oilfield fluid sample obtained from a high specific gravity solid (HGS) recovery system or a dewatering system, as described in more detail below with reference to FIG. 6 . At 104, the oilfield fluid sample is stirred with a viscosity modifier including a high surface area powder such as carbon black to convert the sample into a high viscosity paste (or paste sample). Then, at 106, the paste (including the fluid sample and the viscosity modifier) ​​is introduced into an XRF measurement device, for example, in a pre-configured sample holder. XRF measurements are taken at 108 and evaluated at 110 to estimate the elemental composition of the multiphase fluid. It should be understood that estimating the elemental composition of the multiphase fluid does not necessarily include determining the amount of each element in the fluid, but can simply include determining whether a particular element is present above a detection limit, or estimating the amount of one or more elements in the fluid (or an increase or decrease from a previous measurement).

[0024] Continue to refer Figure 2 It will be appreciated that stirring the drilling fluid sample with the viscosity modifier significantly increases the viscosity of the sample, thereby preventing (or significantly delaying or slowing down) phase separation and precipitation of high density components in the fluid. It will be appreciated that the precipitation of solids in a multiphase fluid is a kinetic process, and that the viscosity modifier is added to reduce the precipitation rate (or velocity) of the solids. Reducing the precipitation rate can be achieved, for example, by increasing the viscosity of the fluid at low shear rates and / or by providing the fluid with a large yield stress. In an exemplary embodiment, at a rate such as 1 s -1At low shear rates of 100 P or 10 Pa·s, a viscosity greater than about 100 P or 10 Pa·s may be sufficient to prevent precipitation in the drilling fluid within the time frame required to obtain XRF measurements (e.g., greater than about 200 P, greater than about 500 P, or greater than about 1000 P). With respect to yield stress, a yield stress greater than about 10 Pa may be sufficient to prevent precipitation in the drilling fluid within the time frame required to obtain XRF measurements (e.g., greater than about 20 Pa, greater than about 50 Pa, or greater than about 100 Pa).

[0025] In an advantageous embodiment, a sufficient amount of high surface area powder is added to the sample so as to convert the sample into a paste. The amount of powder added to the drilling fluid sample generally depends on the mass (or volume) of the sample, the type of fluid, and the type of powder used. In an exemplary embodiment where the high surface area powder is carbon black, the amount of powder may be from a weight ratio of 10 parts powder to 1 part oilfield fluid (10:1) to a weight ratio of 1 part powder to approximately 100 parts oilfield fluid (1:100). For example, in some applications, it may be advantageous to provide a high dilution factor for evaluating highly concentrated elements or elements with partially overlapping peaks. In such an embodiment, a weight ratio ranging from about 10 parts powder to 1 part oilfield fluid (10:1) to about 1 part powder to about 1 part oilfield fluid (1:1) may be advantageous. In other exemplary applications, it may be advantageous to use as little powder as possible to obtain a paste with a sufficiently high viscosity so as not to overly dilute the original oilfield fluid sample. In such embodiments, a weight ratio ranging from about 1 part powder to about 1 part oilfield fluid (1:1) to about 1 part powder to about 100 parts oilfield fluid (1:100) may be advantageous (e.g., from about 1:2 to about 1:50, from about 1:3 to about 1:19, or from about 1:3 to about 1:9). In other exemplary applications, for example, where the oilfield fluid has a high initial viscosity, a weight ratio ranging from about 1 part powder to about 20 parts oilfield fluid (1:20) to about 1 part powder to about 100 parts oilfield fluid (1:100) may be advantageous. Of course, it should be understood that the oilfield fluid and the viscosity modifier can be stirred by volume. Based on the density of the oilfield fluid and the viscosity modifier, one of ordinary skill in the art will be able to easily convert the weight ratio to a volume ratio, or convert the volume ratio to a weight ratio.

[0026] The viscosity modifier may include substantially any suitable powder, including, for example, carbon black, fumed silica, alumina, and other powders. Carbon black, particularly high surface area carbon black, may be advantageously used because small amounts of carbon black may significantly increase sample viscosity and promote the formation of a paste. In addition, carbon black (substantially entirely carbon) is advantageously not detected by XRF measurements and therefore does not affect the estimated elemental composition of the drilling fluid. Of course, it should be understood that carbon black may contain trace impurities. These impurities may be ignored in certain operations. In other operations, it may be advantageous to measure the XRF spectrum of the carbon black and subtract (or otherwise take into account) any impurities in the subsequent spectrum obtained from the paste sample.

[0027] It will be appreciated that essentially any suitable carbon black may be used, for example, carbon black having a surface area of ​​about 80 m 2 / g to about 1000m 2 Although carbon blacks with larger surface areas may be advantageous because less carbon black is needed to obtain a high viscosity paste, the disclosed embodiments are expressly not limited in this regard.

[0028] Still further reference Figure 2 Advantageous embodiments of the method 100 may be automated or semi-automated. For example, a drilling fluid sample may be collected from a flow line or from a mud pit ( Figure 1 ) is automatically pumped to a mixer. Carbon black (or other powders) can be automatically metered into the mixer before or after receiving the drilling fluid sample and then automatically mixed with the powder. After mixing, the high viscosity paste can be automatically injected (or otherwise transferred) into a sample cup (or holder), which can be automatically transferred to the XRF chamber for measurement. The XRF measurement can be triggered automatically or manually, and the corresponding spectrum (or multiple spectra) can be saved and evaluated on a computer.

[0029] It should be understood that estimating the composition of an oilfield (e.g., drilling) fluid may enable adjustment of the composition of the fluid (or adjustment of other drilling parameters). For example, a simultaneous increase in the amount of potassium, aluminum, silicon, and possibly thorium and / or uranium in a drilling fluid may indicate an increased clay concentration or a high and / or increased clay index. In response, an automatic (or manual) command may be generated to increase the amount of shale inhibitors and sealants in the drilling fluid. Commands to increase drilling fluid flow and / or reduce drilling pressure may also be generated. A decrease in barium content may indicate a loss of HGS during the drilling operation. The driller may choose to add additional barite to the drilling fluid, or investigate the loss and evaluate other remedial measures. In addition, an increase in sodium and chloride content may indicate that the wellbore is entering a salt formation. Additives suitable for drilling in salt formations may be added to the drilling fluid.

[0030] Figure 3 An example embodiment of a system 150 for performing XRF measurements on oilfield fluids used during drilling operations is depicted. In the depicted embodiment, a mixer (or agitator) 160 is in fluid communication with a mud pit, tank, or fluid flow line, for example, including a return conduit 52, a standpipe 58, a mud hose 59, or a flow line between a shale shaker 55 and a mud pit 56 ( Figure 1 ). The agitator 160 is further in fluid communication with a carbon black (or other high surface area powder) tank 170 and an XRF sample dispenser 180. A drilling fluid sample can be drawn or received into the agitator 160 by opening valve 162 and closing valve 164. Carbon black can be added to the agitator 160 from a carbon black tank by opening a metering element 172, which includes, for example, a valve, an auger, an Archimedean screw, an extruder, a twin screw extruder, a solid vibrating screen, or any other solid powder metering device.

[0031] The agitator can be configured to shear its contents, thereby converting the carbon black drilling fluid sample mixture into a high viscosity fluid or paste. By opening the valve 166, the resulting paste can be transferred to the sample dispenser 180. The dispenser can include an electric injector 182, which is configured to dispense a predetermined volume of the paste into a sample holder 185. The sample holder can include a plurality of sample cups 187, for example, arranged in a carousel. The individual samples can be rotated (one after another) by the XRF device 190 to obtain corresponding XRF measurements of the samples. Of course, it should be understood that the system 150 (or portions thereof) can be flushed, for example, using a base oil to avoid cross contamination between measurements.

[0032] Continue to refer Figure 3 , the XRF instrument 190 may include substantially any suitable XRF device, including, for example, a portable device such as the Epsilon 1 available from Malvern® Instruments. In an example embodiment, the XRF instrument 190 may include a vacuum pump and a vacuum sample chamber for performing XRF measurements under vacuum (or low pressure), an X-ray tube, a Si-drift detector, corresponding electronic devices, and a temperature controller for controlling the sample chamber temperature. The XRF instrument 190 may be integrated with a sample turntable for performing automatic or semi-automatic measurements.

[0033] Continue to refer Figure 2 and Figure 3It should be understood that converting oilfield fluids into pastes as described above can bring multiple advantages. For example, converting fluids into pastes can enable XRF measurements to be performed under vacuum (or very low pressure), where light elements such as sodium (Na) and magnesium (Mg) can be measured more accurately. In addition, converting fluids into pastes can enable longer measurement times (because the pastes will not precipitate or otherwise separate), thereby improving the signal-to-noise ratio of the measurements and the corresponding accuracy of element determination (particularly for trace element detection and quantification, such as nickel, chromium, cobalt, thorium and / or uranium). Converting drilling fluids into pastes can further enable the development and use of robust and customized calibration procedures.

[0034] Figure 4A and 4B (collectively referred to as FIG. 4 ) depicts portions of a measured XRF spectrum (XRF measurement) obtained from a drilling fluid sample (4A) and from a paste sample (4B) obtained by stirring the drilling fluid sample with carbon black as described above. The drilling fluid sample was a water-based drilling fluid containing 40 wt % barite. The sample was mixed to maintain a uniform distribution of the barite in the fluid. The sample was then transferred to a cup and XRF spectra were obtained at times 0, 7 minutes, 14 minutes, 21 minutes, 60 minutes, 67 minutes, and 120 minutes after the sample was transferred to the cup. Figure 4A The barium La1 peak for each of these spectra is shown in . Note that the barium peak height increases significantly with time, indicating that barite is precipitated at the bottom of the sample cup.

[0035] The paste samples were prepared by combining 4 parts by weight of drilling fluid with 1 part by weight of carbon black to form a paste. XRF spectra of the paste samples were obtained at the initial time, one day, and two days. Figure 4B The barium La1 peak for each of these spectra is shown in . Note that the barium peak is highly stable over time, indicating that the drilling fluid has stabilized in the paste sample.

[0036] Figure 5 The barium peak height is plotted against time (in minutes) for four different paste samples. In this example, each of the four paste samples consisted of 14 lb / gal (1.68 g / cm 3) of a barite-containing water-based drilling fluid (HydraGlyde®, available from Schlumberger). The stirred samples included 5 wt%, 10 wt%, 15 wt%, and 20 wt% carbon black (weight ratios of 1:19, 1:9, 1:5.7, and 1:4). The viscosity of the stirred samples increased significantly with the increase of carbon black. The third and fourth samples (including 15 wt% and 20 wt% carbon black) were thick and pasty (with very high viscosity). These samples showed a stable (constant) barium peak height for at least 15 minutes, indicating that the barite particles did not precipitate. The second sample (comprising 10 wt. % carbon black) was a highly viscous liquid and exhibited a nearly constant barium peak height (the peak height was observed to increase by about 1-2 % (about 300 counts) over 17 minutes). The first sample (comprising 5 wt. % carbon black) was a medium viscosity liquid and exhibited an unstable barium peak height (indicating precipitation of barite in the drilling fluid). The barium peak height was observed to increase by about 135 counts per minute over 17 minutes, from about 19,500 to about 21,800 (an increase of nearly 12%). Based on the above, it is apparent that stirring the carbon black with the drilling fluid sample to form a paste can significantly improve the stability of the XRF measurement.

[0037] Fig. 6A and 6B (collectively, FIG. 6 ) depicts a portion of a measured XRF spectrum (XRF measurement) obtained from a paste sample comprising a mixture of drilling fluid and carbon black. Each paste sample was prepared by combining 9 parts by weight of drilling fluid with 1 part by weight of carbon black to form a paste. In order to obtain Fig. 6A Spectra shown, four water-based drilling fluids were prepared containing 15, 25, 33 and 40 wt% barite. Corresponding paste samples were prepared and evaluated to obtain the depicted XRF spectra. Note that, as expected, the peak height of the barium La1 peak increases with increasing amount of barite in the drilling fluid.

[0038] To obtain Figure 6B Spectra shown, four water-based drilling fluids were prepared, including 15, 25, 33 and 40 wt% of American Petroleum Institute (API) clay, respectively. Corresponding paste samples were prepared (by combining 9 parts by weight of drilling fluid with 1 part by weight of carbon black) and evaluated to obtain the XRF spectra depicted. Note that, as expected, the peak height of the silicon Ka1 peak increases with increasing amount of barite in the drilling fluid.

[0039] like Figure 5As shown in Figures 4 and 5, the peak height of an element (e.g., barium or silicon) depends on the concentration of the element in the drilling fluid and the relative amount of carbon black used to form the paste (the peak height generally increases with increasing amounts of the element in the drilling fluid and generally decreases with increasing amounts of carbon black in the paste). As further shown in Figures 4 and 5, for a paste containing a sufficient amount of carbon black (e.g., having a sufficiently high viscosity to prevent precipitation), the measured element peak height is stable over time. It should be understood that for such paste samples, a reliable calibration can be advantageously obtained. For example, a calibration can be obtained by evaluating multiple paste samples having known concentrations of various drilling fluid components (known element concentrations) and establishing a correlation between the observed peak heights (or areas under peaks) and the known concentrations. Such calibration may include Compton peak normalization or Compton / Rayleigh peak ratios known to those of ordinary skill. The disclosed embodiments are not limited to any particular calibration or calibration method.

[0040] It should be understood that the disclosed embodiments are expressly not limited to evaluating drilling fluids, but can be applied to substantially any multiphase oilfield fluid, including, for example, drilling fluids, reservoir drilling fluids, completion fluids, produced water, and recycle or waste water and fluids. In this exemplary application, a sample of a multiphase oilfield fluid is first stirred with a viscosity adjusting powder, such as carbon black, to convert the multiphase fluid into a paste (e.g., as described above with respect to Figure 2 The paste is then evaluated with an XRF instrument to estimate the elemental composition of the multiphase fluid (including the entire fluid of its multiple phases).

[0041] Figure 7A process diagram 200 is depicted of an example of a drilling fluid (e.g., WBM) dewatering process for an example drilling fluid, including high density solids (HSG) (e.g., primarily large particles and high density solids such as barite) recovery and low specific gravity solids (LGS) (e.g., primarily very small particles and low density solids such as silica and clay) removal. In the depicted example, the drilling fluid flows from a solids control device 204 (e.g., a shale shaker) into a mud pit 202 (or mud pit system) where the drilling fluid may be conditioned or modified before being pumped downhole at 206. From the mud pit 202, the drilling fluid is received into a HSG recovery system 210, for example, via a flow line 212 and a pump 214 (e.g., a centrifugal pump). The received drilling fluid is pumped through a HGS recovery centrifuge 216, which is configured to remove a portion of the HGS (e.g., barite) from the drilling fluid and return the recovered HSG (centrifuge) to the mud pit, as depicted at 218. The supernatant 219 (also referred to herein as dewatered fluid) can be transferred to a dewatering system 220 (which may or may not include a storage tank 222). In the event that a storage tank is not available, a pipeline connecting the centrifuge 216 to the dewatering system 220 is used to transfer the supernatant 219. As described in more detail below, the HSG recovery system 210 can optionally include one or more XRF measurement systems 250.

[0042] As used herein, the term high specific gravity solid (HGS) refers to dense solids, such as barite, calcium carbonate and / or hematite, which are added to the drilling fluid to increase its density. HGS is also commonly referred to in the art as weighting material and typically has a density of more than 4 g / cm 3 As used herein, the term low specific gravity solids (LGS) refers to dispersed low density solids that are not captured in the solid control vibrator, such as finely ground drill cuttings and / or added clay (e.g., bentonite). One of ordinary skill in the art will appreciate that the HSG recovery system 210 can be configured to remove HSG from the drilling fluid (in the centrifuge) while leaving the LGS in the supernatant. For example, the flow rate of the drilling fluid and the speed of the centrifuge can be adjusted (optimized) so that the centrifuge primarily (or mostly) removes HSG. Therefore, in many operations, the drilling fluid in the dewatering tank 222 typically includes LSG (and a small amount of HSG).

[0043] The drilling fluid in the storage tank 222 may be transferred to a mixer 224 (e.g., a static mixer or agitator). One or more chemical additives, such as coagulants and / or acids in water and aqueous solutions, may be added to the mixer, as depicted at 226. After mixing with the additives, the drilling fluid may be pumped 228 through a dewatering centrifuge 230, which is configured to concentrate and remove LGS (and any remaining HGS) at 232. As depicted, one or more polymer additives 229 (flocculants dissolved in water) may be injected into the drilling fluid prior to centrifugation, typically with some pipeline or tank residence time to allow them residence time to increase their effectiveness and enhance particle coagulation / flocculation and separation in the centrifuge. The supernatant from the centrifuge 230 (also referred to as clean centrate) may then be transferred to a holding tank 234 where it may be optionally further processed, diluted, etc., before being recycled back into the mud pond 202, or may be deemed redundant and disposed of from the process 235. As also described in more detail below, the dewatering system 220 may optionally include one or more XRF measurement systems 250.

[0044] Continuing with reference to FIG. 6 , a fluid sample may be obtained at substantially any suitable location in the HGS recovery system 210 and / or the dewatering system 220 , agitated with a high surface area powder such as carbon black to convert the sample to a high viscosity paste, and evaluated using XRF, as described above with reference to Figure 2 As described. In an example embodiment, a fluid sample can be obtained from the supernatant of the HGS recovery centrifuge 216 (dehydrated fluid sample). The obtained XRF spectrum can then be evaluated, for example, for the presence of barium, manganese, iron, or calcium, to indicate the amount of HGS (e.g., barite, hematite, manganese oxide, or in some cases calcium carbonate, or calcium carbonate / magnesium carbonate, or any other high specific gravity solid that can be used in the drilling fluid) remaining in the supernatant (e.g., to determine the effectiveness of the HGS recovery operation). It should be understood that a high concentration of HGS in the supernatant may indicate that the HGS recovery operation is inefficient, while a low concentration of HGS in the supernatant may indicate that the HGS recovery operation is efficient. In addition, it should be understood that the drilling fluid flow rate through the centrifuge and the rotational speed of the centrifuge can be adjusted in response to the XRF measurement.

[0045] In other example embodiments, the fluid sample (or another fluid sample) can be obtained from the supernatant (cleaned centrate fluid sample) of the dewatering centrifuge 230. The obtained XRF spectrum can then be evaluated, for example, for the presence of calcium, magnesium, silicon, aluminum, thorium, uranium, etc., to indicate the amount of LGS (e.g., formation minerals, silica, feldspard, and clay) remaining in the supernatant (e.g., to determine the effectiveness of the LGS removal operation). It should be understood that a high concentration of LGS in the supernatant may indicate an inefficient dewatering operation, while a low concentration of LGS in the supernatant may indicate a high efficiency of the dewatering operation. In addition, it should be understood that the drilling fluid flow rate through the centrifuge, the rotational speed of the centrifuge, and the mass of chemical additives (e.g., flocculants or coagulants) added to the mixer can be adjusted in response to the XRF measurement.

[0046] Still further reference Figure 7 , the XRF measurement can be evaluated to determine whether there is a coagulant in the supernatant. In some dewatering operations, the coagulant may include aluminum sulfate or aluminum chloride or polyaluminum chloride. In such operations, it may not be desirable to recycle aluminum into the mud pond because this may have a detrimental effect on the drilling mud viscosity. The XRF measurement of the supernatant from the dewatering centrifuge 230 can be evaluated to determine whether aluminum is present in the stream, and this measurement can be used to control the amount of coagulant and flocculant added to the mixer. Those skilled in the art will understand that selecting an appropriate aluminum carryover level means a balance between the amount of LGS solids returned to the mud pond and the extent to which solids and other drilling mud chemicals are removed by the coagulation and flocculation processes, as needed, which is optimal for each drilling fluid, operation and rig.

[0047] As described above, drilling fluid samples may be obtained at substantially any suitable location in the HGS recovery system 210 and / or the dewatering system 220. Other suitable locations may include, for example, the input and centrate output of the HGS recovery centrifuge 216 and the dewatering centrifuge 230, as well as the return line of the mud pit 202. It should be appreciated that obtaining drilling fluid samples from each input and centrate and supernatant output of the centrifuges 216, 230 may advantageously enable a mass balance to be determined (estimated) for each centrifuge. Such a mass balance may determine the efficiency of the centrifuge in removing HGS and LGS from the drilling fluid.

[0048] Figure 8A graph of the volume percentage of LGS on the vertical axis versus the volume percentage of HGS on the horizontal axis for an example dewatering operation is depicted. Raw drilling fluid from a mud tank is shown at 302. As shown at 310, the HGS recovery centrifuge 216 separates the raw drilling fluid into a centrate 312 containing a high percentage of HGS and a supernatant 314 containing a low percentage of HGS. As described above, the centrate 312 can be recycled (returned to the mud tank) while the supernatant is transferred to the dewatering system 220. As shown at 320, the dewatering centrifuge 230 separates the fluid 314 into a centrate 322 containing a high percentage of LGS and a supernatant 324 containing a low percentage of LGS and HGS. As described above, the supernatant 324 can be recycled, while the centrate (including LGS) is discarded. The combination of recovered centrate 312 and supernatant 324 is shown at 334 and includes a 50% reduction in LGS (12 vol% to 6 vol%) at the expense of a 5% reduction in HGS (10 vol% to 9.5 vol%).

[0049] Further references Figure 7 It will be appreciated that the XRF measurements may be performed automatically or semi-automatically, for example, as described above with reference to Figure 2 and 3 In such an embodiment, the XRF measurement system 250 may be used with Figure 3 The depicted XRF measurement systems 150 are similar (or even substantially identical).

[0050] In addition, this automatic or semi-automatic XRF measurement can be used for automatic or semi-automatic Figure 7 The HGS solids recovery and dewatering process depicted. In an exemplary embodiment of performing XRF measurements on the supernatant of an HGS recovery centrifuge, the peak height or peak area of ​​a predetermined peak (or peaks) in the XRF spectrum can be automatically evaluated and used to control the flow rate of drilling fluid entering the centrifuge and / or the rotation speed of the centrifuge. For example, when the XRF spectrum indicates that the amount of HGS solids is above a threshold, the rotation rate of the centrifuge can be increased or the flow rate of drilling fluid entering the centrifuge can be reduced to improve the efficiency of the centrifuge.

[0051] In another exemplary embodiment of performing XRF measurements on the supernatant of a dewatering centrifuge, the peak height or peak area of ​​a predetermined peak (or peaks) in the XRF spectrum can be automatically evaluated and used to control the flow rate of drilling fluid entering the centrifuge and / or the rotational speed of the centrifuge. For example, when the XRF spectrum indicates that the amount of LGS solids is above a threshold, the rotation rate of the centrifuge can be increased or the flow rate of drilling fluid entering the centrifuge can be reduced to improve the efficiency of the centrifuge. Or when the XRF spectrum indicates that the amount of aluminum is above a threshold, the amount of coagulant added to the mixer can be reduced, and / or the amount of flocculant can be increased. Of course, it should be understood that the disclosed embodiments are not limited to these example automated implementations.

[0052] Although Figure 7 A dewatering process for WBM is described, but it should be understood that a similar process can be used for oil-based invert emulsion drilling fluids, where the supernatant stream obtained in the centrifuge is a brine-in-oil emulsion. In addition, a similar method can be used for direct emulsified drilling fluids, where the supernatant obtained in the centrifuge is an oil-in-water emulsion. By performing chemical composition XRF analysis of the different streams using the sample preparation and analysis methods described herein, the control of HGS and LGS can be optimized into each stream.

[0053] It will be understood that the present disclosure includes many embodiments. These embodiments include but are not limited to the following embodiments.

[0054] In a first embodiment, a method for estimating the elemental composition of a multiphase oilfield fluid includes: obtaining a sample of the multiphase oilfield fluid; stirring the sample with a viscosity modifier to convert the sample into a high viscosity paste; introducing the high viscosity paste into a chamber of an x-ray fluorescence (XRF) device; performing XRF measurements on the high viscosity paste using the XRF device; and evaluating the XRF measurements to estimate the elemental composition of the obtained multiphase oilfield fluid.

[0055] A second embodiment may include the first embodiment wherein the obtained sample comprises a sample of a drilling fluid used in a wellbore drilling operation.

[0056] A third embodiment may include the second embodiment, further comprising adjusting an actual composition of the drilling fluid in the mud pit in response to the estimated elemental composition.

[0057] A fourth embodiment may include any one of the first to third embodiments, wherein the viscosity modifier includes carbon black.

[0058] A fifth embodiment may include any one of the first to fourth embodiments, wherein a sample of a multiphase oilfield fluid is automatically obtained from a flow line, mud pit, or tank; the obtained sample is automatically stirred with a viscosity modifier to convert the obtained sample into a high viscosity paste; and the high viscosity paste is automatically dispensed into a sample cup and transferred to a chamber of an XRF device for XRF measurement.

[0059] A sixth embodiment may include any one of the first to fifth embodiments, wherein evaluating the XRF measurement further comprises: establishing a correlation between the peak height or area under the peak in the XRF measurement and the element concentration in the multiphase oilfield fluid; and using the correlation to evaluate the peak height or area under the peak in the XRF measurement to estimate the elemental composition of the multiphase oilfield fluid.

[0060] A seventh embodiment may include any one of the first to sixth embodiments, wherein the multiphase oilfield fluid is a dewatered fluid obtained from a high specific gravity solids (HGS) recovery system during a drilling fluid dewatering process; and evaluating the XRF measurement also includes evaluating the XRF measurement of at least one of barium, manganese, iron, or calcium to estimate the amount of HGS in the dewatered fluid.

[0061] An eighth embodiment may include the seventh embodiment, further comprising adjusting an operating parameter of the HGS recovery system in response to the estimated amount of HGS in the dewatered fluid.

[0062] A ninth embodiment may include any one of the first to eighth embodiments, wherein the multiphase oilfield fluid is a clean centrate obtained from a low specific gravity solids (LGS) removal system during a drilling fluid dewatering process; and evaluating the XRF measurement also includes evaluating the XRF measurement of at least one of calcium, magnesium, silicon, aluminum, thorium, or uranium to estimate the amount of LGS in the clean centrate.

[0063] A tenth embodiment may include the ninth embodiment, further comprising adjusting an operating parameter of the LGS removal system in response to the estimated amount of LGS in the clean centrate.

[0064] In an eleventh embodiment, a system for estimating the elemental composition of a multiphase oilfield fluid comprises: a fluid input port configured for receiving a sample of the multiphase oilfield fluid; a mixer configured to mix the received sample with carbon black to convert the received sample into a high viscosity paste; an x-ray fluorescence (XRF) sample holder configured to receive the high viscosity paste; an XRF measurement tool configured to perform XRF measurements on the high viscosity paste; and a processor configured to evaluate the XRF measurements to estimate the elemental composition of the multiphase oilfield fluid.

[0065] A twelfth embodiment may include the eleventh embodiment, further comprising a carbon black holding vessel configured to transfer the carbon black to the mixer.

[0066] A thirteenth embodiment may include any one of the eleventh to twelfth embodiments, further comprising a paste dispenser configured to transfer a high viscosity paste to a sample holder; and a turntable comprising a plurality of sample holders.

[0067] A fourteenth embodiment may include the thirteenth embodiment, wherein the mixer is configured to automatically receive a sample of a multiphase oilfield fluid and carbon black, and automatically stir the received sample and the received carbon black to convert the received sample into a high viscosity paste; and the paste dispenser is configured to automatically transfer the high viscosity paste to the sample holder.

[0068] A fifteenth embodiment may include any one of the eleventh to fourteenth embodiments, wherein the processor includes a correlation between peak height or area under peak in XRF measurements and elemental concentration in multiphase oilfield fluid; and the processor is further configured to utilize the correlation to evaluate the peak height or area under peak in the XRF measurements to estimate the elemental composition of the multiphase oilfield fluid.

[0069] In a sixteenth embodiment, a method for evaluating a multiphase dehydrated fluid includes obtaining a sample of the multiphase dehydrated fluid from a high specific gravity solid (HGS) recovery system or a low specific gravity solid (LGS) removal system during a dehydration process; stirring the obtained sample with carbon black to convert the obtained sample into a paste; and performing XRF measurement on the paste to estimate the elemental composition of the dehydrated fluid.

[0070] A seventeenth embodiment may include the sixteenth embodiment, wherein the multiphase dehydrated fluid is obtained from a HGS recovery system; and performing the XRF measurement further comprises evaluating the XRF measurement of at least one of barium, manganese, iron, or calcium to estimate the amount of HGS in the multiphase dehydrated fluid.

[0071] An eighteenth embodiment may include the seventeenth embodiment, further comprising adjusting an operating parameter of a centrifuge in the HGS recovery system in response to the estimated amount of HGS in the dewatered fluid.

[0072] A nineteenth embodiment may include any one of the sixteenth to eighteenth embodiments, wherein a multiphase dehydrated fluid is obtained from a LGS removal system; and performing XRF measurements further comprises evaluating XRF measurements of at least one of calcium, magnesium, silicon, aluminum, thorium, or uranium to estimate the amount of LGS in the multiphase dehydrated fluid.

[0073] A twentieth embodiment may include the nineteenth embodiment, further comprising adjusting an operating parameter of a centrifuge in the LGS removal system in response to the estimated amount of LGS in the multiphase dewatered fluid.

[0074] Although the XRF measurement of multiphase oilfield fluids has been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.

Claims

1. A method for estimating the elemental composition of a multiphase oilfield fluid, the method comprising: obtaining samples of multiphase oilfield fluids; stirring the sample with a viscosity modifier to convert the sample into a high viscosity paste; introducing a high viscosity paste into a chamber of an x-ray fluorescence (XRF) device; XRF measurement of high viscosity pastes using an XRF device; and XRF measurements were evaluated to estimate the elemental composition of the obtained multiphase oilfield fluids.

2. The method of claim 1, wherein the sample obtained comprises a sample of a drilling fluid used in a wellbore drilling operation.

3. The method of claim 2, further comprising adjusting an actual composition of the drilling fluid in the mud pit in response to the estimated elemental composition.

4. The method of claim 1, wherein the viscosity modifier comprises carbon black.

5. The method according to claim 1, wherein: Samples of multiphase oilfield fluids are automatically obtained from flow lines, mud pits, or tanks; automatically stirring the obtained sample with a viscosity modifier to convert the obtained sample into a high viscosity paste; and The high viscosity paste is automatically dispensed into a sample cup and transferred into the chamber of the XRF device for XRF measurement.

6. The method of claim 1 , wherein evaluating the XRF measurements further comprises: Correlate peak height or area under peak in XRF measurements with element concentrations in multiphase oilfield fluids; and This correlation is used to evaluate peak heights or areas under peaks in XRF measurements to estimate the elemental composition of multiphase oilfield fluids.

7. The method according to claim 1, wherein: Multiphase oilfield fluids are dewatered fluids obtained from high gravity solids (HGS) recovery systems during the dehydration of drilling fluids; and Evaluating the XRF measurement also includes evaluating the XRF measurement of at least one of barium, manganese, iron, or calcium to estimate the amount of HGS in the dehydrated fluid.

8. The method of claim 7, further comprising adjusting an operating parameter of the HGS recovery system in response to the estimated amount of HGS in the dewatered fluid.

9. The method according to claim 1, wherein: Multiphase oilfield fluids are clean centrate fluids obtained from low gravity solids (LGS) removal systems during drilling fluid dewatering; and Evaluating the XRF measurement also includes evaluating the XRF measurement of at least one of calcium, magnesium, silicon, aluminum, thorium, or uranium to estimate the amount of LGS in the clean centrate fluid.

10. The method of claim 9, further comprising adjusting an operating parameter of the LGS removal system in response to the estimated amount of LGS in the clean centrate fluid.

11. A system for estimating the elemental composition of a multiphase oilfield fluid, the system comprising: a fluid input port configured to receive a sample of a multiphase oilfield fluid; a mixer configured to mix the received sample with carbon black to convert the received sample into a high viscosity paste; an x-ray fluorescence (XRF) sample holder configured to receive a high viscosity paste; An XRF measurement tool configured to perform XRF measurement on a high viscosity paste; and A processor is configured to evaluate the XRF measurements to estimate elemental composition of a multiphase oilfield fluid.

12. The system of claim 11, further comprising a carbon black holding vessel configured to transfer the carbon black to the mixer.

13. The system of claim 11, further comprising: a paste dispenser configured to transfer a high viscosity paste to the sample holder; and A carousel comprising multiple sample holders.

14. The system of claim 13, wherein: The mixer is configured to automatically receive a sample of a multiphase oilfield fluid and carbon black and to automatically stir the received sample and the received carbon black to convert the received sample into a high viscosity paste; and The paste dispenser is configured to automatically transfer a high viscosity paste to a sample holder.

15. The system of claim 11, wherein: The processor includes correlation between peak height or area under peak in XRF measurements and element concentration in multiphase oilfield fluids; and The processor is also configured to use the correlation to evaluate peak heights or areas under peaks in the XRF measurements to estimate elemental composition of multiphase oilfield fluids.

16. A method for evaluating a multiphase dehydrated fluid, the method comprising: obtaining a sample of the multiphase dewatered fluid from a high specific gravity solids (HGS) recovery system or a low specific gravity solids (LGS) removal system during the dewatering process; stirring the obtained sample with carbon black to convert the obtained sample into a paste; and XRF measurements were performed on the paste to estimate the elemental composition of the dehydrated fluid.

17. The method of claim 16, wherein: The multiphase dehydrated fluid is obtained from the HGS recovery system; and Performing the XRF measurement also includes evaluating the XRF measurement of at least one of barium, manganese, iron, or calcium to estimate the amount of HGS in the multiphase dehydrated fluid.

18. The method of claim 17, further comprising adjusting an operating parameter of a centrifuge in the HGS recovery system in response to the estimated amount of HGS in the dewatered fluid.

19. The method of claim 16, wherein: The multiphase dewatered fluid is obtained from the LGS removal system; and Performing XRF measurements also includes evaluating XRF measurements of at least one of calcium, magnesium, silicon, aluminum, thorium, or uranium to estimate an amount of LGS in the multiphase dehydrated fluid.

20. The method of claim 19, further comprising adjusting an operating parameter of a centrifuge in the LGS removal system in response to the estimated amount of LGS in the multiphase dewatered fluid.

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