CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to European Patent Application No. 22306342.1, which was filed on September 12, 2022, and is incorporated herein by reference in its entirety.

BACKGROUND

[0002] Mud logging is the creation of a detailed record (i.e., a well log) of a wellbore by analyzing the cuttings of rock brought to the surface by a circulating drilling fluid (also referred to as mud or drilling mud) while drilling the wellbore. In mud logging operations, gas may be extracted from the drilling fluid. The gas may then be analyzed to detect the presence of hydrocarbons in the subterranean formation. This extraction and analysis is conventionally done by placing a first gas extractor proximate to a shale shaker at the outlet of the wellbore (i.e., HC OUT).

[0003] The first gas extractor at the outlet of the wellbore may sample a portion of the drilling fluid that flows up and out of the wellbore and extract and detect the hydrocarbon fraction in the sample. For example, the first gas extractor may sample about 300 mL/minute of the drilling fluid. The remainder of the drilling fluid may flow from the first gas extractor downstream at the surface of the wellsite to a second gas extractor that is placed proximate to a mud pit at the inlet of the wellbore (i.e., HC IN). The drilling fluid may be naturally degassed while flowing at the surface from the first gas extractor to the second gas extractor. The second gas extractor may also sample a portion of the drilling fluid and extract and detect the hydrocarbon fraction therein. The hydrocarbon fraction detected by the second gas extractor may be subtracted from the hydrocarbon fraction detected by the first gas extractor (and resynchronized in depth) to determine the actual hydrocarbon contribution from the subterranean formation at the bottom of the wellbore.

SUMMARY

[0004] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0005] A system for detecting hydrocarbons in a subterranean formation is disclosed. The system includes an outlet sensor positioned downstream from an outlet of a wellbore and upstream from or at least partially within a shaker. The outlet sensor is configured to measure an outlet drilling fluid parameter of a drilling fluid. The system also includes an inlet sensor positioned downstream from the outlet sensor and upstream from an inlet of the wellbore. The inlet sensor is configured to measure an inlet drilling fluid parameter of the drilling fluid. The system also includes a gas extractor positioned downstream from the outlet of the wellbore and upstream from the inlet sensor. The gas extractor is configured to extract a gas from the drilling fluid. The system also includes a computing system configured to determine a first time when the outlet drilling fluid parameter increases by more than a first threshold, determine a second time when the inlet drilling fluid parameter becomes substantially constant or increases by more than a second threshold, and determine a surface transit time of the drilling fluid based at least partially upon the first time and the second time.

[0006] A non-transitory computer-readable medium is also disclosed. The medium stores instructions that, when executed by at least one processor of a computing system, cause the computing system to perform operations. The operations include receiving an outlet drilling fluid parameter measured by an outlet sensor. The outlet drilling fluid parameter includes a level or a flow rate of a drilling fluid. The outlet sensor is positioned downstream from an outlet of a wellbore. The operations also include determining a first time when the outlet drilling fluid parameter increases by more than a predetermined outlet drilling fluid parameter threshold. The operations also include receiving an inlet drilling fluid parameter measured by an inlet sensor. The inlet drilling fluid parameter includes the level or the flow rate. The inlet sensor is positioned downstream from the outlet sensor and upstream from an inlet of the wellbore. The operations also include determining a second time when the inlet drilling fluid parameter becomes substantially constant or increases by more than a predetermined inlet drilling fluid parameter threshold. The operations also include determining a surface transit time of the drilling fluid by subtracting the first time from the second time. The operations also include determining an outlet hydrocarbon contribution in the drilling fluid based at least partially upon gas extracted from the drilling fluid by a gas extractor. The gas extractor is positioned at the outlet of the wellbore, at a shaker, or between the outlet of the wellbore and the shaker. The operations also include determining an inlet hydrocarbon contribution in the drilling fluid based at least partially upon the surface transit time and the outlet hydrocarbon contribution.

[0007] A computing system is also disclosed. The computing system includes one or more processors and a memory system. The memory system includes one or more non-transitory computer-readable media storing instructions that, when executed by at least one of the one or more processors, cause the computing system to perform operations. The operations include receiving an outlet drilling fluid parameter measured by an outlet sensor. The outlet drilling fluid parameter includes a level or a flow rate of a drilling fluid. The outlet sensor may include a first level sensor configured to measure the level of the drilling fluid in a shaker. The shaker is positioned downstream from an outlet of a wellbore and upstream from an inlet sensor. The outlet sensor may also or instead include a first flow paddle configured to measure the flow rate of the drilling fluid through the outlet of the wellbore, through the shaker, or between the outlet of the wellbore and the shaker. The operations also include determining a first time when the outlet drilling fluid parameter increases by more than a predetermined outlet drilling fluid parameter threshold. The operations also include receiving an inlet drilling fluid parameter measured by the inlet sensor. The inlet drilling fluid parameter includes the level or the flow rate. The inlet sensor may include a second level sensor configured to measure the level of the drilling fluid in a suction tank. The suction tank is positioned downstream from the shaker and upstream from an inlet of the wellbore. The inlet sensor may also or instead include a second flow paddle configured to measure the flow rate of the drilling fluid into the suction tank, into the inlet of the wellbore, or between the suction tank and the inlet of the wellbore. The operations also include determining a second time when the inlet drilling fluid parameter becomes substantially constant or increases by more than a predetermined inlet drilling fluid parameter threshold. The operations also include determining a surface transit time of the drilling fluid by subtracting the first time from the second time. The operations also include determining an outlet hydrocarbon contribution in the drilling fluid based at least partially upon gas extracted from the drilling fluid by an outlet gas extractor. The outlet gas extractor is positioned at the outlet of the wellbore, at the shaker, or between the outlet of the wellbore and the shaker. The operations also include determining an inlet hydrocarbon contribution in the drilling fluid based at least partially upon the surface transit time and the outlet hydrocarbon contribution. The operations also include determining an actual hydrocarbon contribution in the drilling fluid from a subterranean formation by subtracting the inlet hydrocarbon contribution from the outlet hydrocarbon contribution.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] The present disclosure is best understood from the following detailed description when read with the accompanying Figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

[0009] Figure 1 illustrates a schematic view of a wellsite, according to an embodiment.

[0010] Figure 2 illustrates a mud log from the wellsite showing an increase in a flow rate measurement from a flow paddle sensor, according to an embodiment.

[0011] Figure 3 illustrates a mud log from the wellsite showing an increase in a fluid level measurement from a pit level sensor, according to an embodiment.

[0012] Figure 4 illustrates a table showing the data from Figures 2 and 3 in a different format (i.e., numerical rather than graphical), according to an embodiment.

[0013] Figure 5 illustrates a flowchart of a method for determining a hydrocarbon contribution, according to an embodiment.

[0014] Figure 6 illustrates a computing system for performing at least a portion of the method, in accordance with some embodiments.

DETAILED DESCRIPTION

[0015] Illustrative examples of the subject matter claimed below will now be disclosed. In the interest of clarity, not all features of an actual implementation are described in this specification. It will be appreciated that in the development of any such actual implementation, numerous implementation-specific decisions may be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort, even if complex and time-consuming, would be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

[0016] Further, as used herein, the article “a” is intended to have its ordinary meaning in the patent arts, namely “one or more.” Herein, the term “about” when applied to a value generally means within the tolerance range of the equipment used to produce the value, or in some examples, means plus or minus 10%, or plus or minus 5%, or plus or minus 1%, unless otherwise expressly specified. Further, herein the term “substantially” as used herein means a majority, or almost all, or all, or an amount with a range of about 51% to about 100%, for example. Moreover, examples herein are intended to be illustrative only and are presented for discussion purposes and not by way of limitation. [0017] The system and method described herein may determine a hydrocarbon contribution in a drilling fluid and/or in a subterranean formation based at least partially upon measurements from a single gas extractor at a wellsite and a surface transit time (STT) of the drilling fluid at the wellsite. As used herein, the hydrocarbon contribution refers to the amount and/or concentration of the hydrocarbons in the drilling fluid.

[0018] In one embodiment, the single gas extractor may be located proximate to the outlet of the wellbore (HC OUT). In this embodiment, a model may determine the hydrocarbon contribution in the drilling fluid at the inlet of the wellbore (HC IN) based at least partially upon the measured hydrocarbon contribution in the drilling fluid at the outlet of the wellbore (HC OUT). The hydrocarbon contribution in the drilling fluid at the inlet of the wellbore (HC IN) may also be based at least partially upon the surface transit time of the drilling fluid. As used herein, the surface transit time refers to the time for the drilling fluid to flow from the outlet of the wellbore (HC OUT) to the inlet of the wellbore (HC IN). The model may then determine the actual hydrocarbon contribution in the drilling fluid from the subterranean formation based at least partially upon the measured hydrocarbon contribution in the drilling fluid at the outlet of the wellbore (HC OUT) and the determined hydrocarbon contribution in the drilling fluid at the inlet of the wellbore (HC IN).

[0019] In another embodiment, the single gas extractor may be located proximate to the inlet of the wellbore (HC IN). In this embodiment, the model may determine the hydrocarbon contribution in the drilling fluid at the outlet of the wellbore (HC OUT) based at least partially upon the measured hydrocarbon contribution in the drilling fluid at the inlet of the wellbore (HC IN). The hydrocarbon contribution in the drilling fluid at the outlet of the wellbore (HC OUT) may also be based at least partially upon the surface transit time of the drilling fluid. The model may then determine the actual hydrocarbon contribution in the drilling fluid form the subterranean formation based at least partially upon the measured hydrocarbon contribution in the drilling fluid at the inlet of the wellbore (HC IN) and the determined hydrocarbon contribution in the drilling fluid at the outlet of the wellbore (HC OUT).

[0020] Figure 1 illustrates a schematic view of a wellsite 100, according to an embodiment. The wellsite 100 may include a wellbore 102 having an inlet 104 configured to receive the drilling fluid and an outlet 106 configured to discharge the drilling fluid. The wellbore 102 may be formed/drilled in a subterranean formation 108 by a downhole tool 110 that is coupled to a lower end of a drill string 112. [0021] The wellsite 100 may also include a mud pump 120 that is positioned upstream from the wellbore 102. The mud pump 120 may be configured to pump the drilling fluid into the wellbore 102. More particularly, as shown by the arrows, the mud pump 120 may cause the drilling fluid to flow downstream through a standpipe 122, a hose 124, a top drive 126, and into the inlet 104 of the wellbore 102. The drilling fluid may flow down the drill string 112 and out of the downhole tool 110. The drilling fluid may then flow back up the annulus between the drill string 112 and a wall of the wellbore 102. As the drilling fluid flows up the annulus, the drilling fluid may mix/combine with liquids, gases, and/or solids from the subterranean formation 108. The liquids may be or include hydrocarbons, water, brine, or a combination thereof. The gases may be or include hydrocarbons, methane, and the like. The solids may be or include drill cuttings from the formation 108. The drilling fluid may then flow out of the outlet 106 of the wellbore 102.

[0022] The wellsite 100 may also include one or more shakers (one is shown: 130) positioned downstream from the wellbore 102. The shaker 130 may be configured to receive the drilling fluid from the outlet 106 of the wellbore 102. The shaker 130 may be or include a shale shaker that includes a header box 132, one or more screens (one is shown: 134), and a first (e.g., shaker) tank 136 positioned therebelow. The header box 132 may distribute the drilling fluid across the screen(s) 134. The liquid and/or gas portions of the drilling fluid may fall/flow through the screen(s) 134 into the shaker tank 136. The solid portions in the drilling fluid (e.g., larger than the openings in the screen(s) 134) may not fall through the screen(s) 134. Thus, the solid portions are filtered out of the drilling fluid and stored or discarded into a waste pit 138.

[0023] The wellsite 100 may also include a second (e.g., suction) tank 140 that is downstream from the shaker 130. The suction tank 140 may also or instead be referred to as a suction pit. The drilling fluid may flow from the shaker tank 136 into the suction tank 140. The mud pump 120 may pump the drilling fluid from the suction tank 140 into the inlet 104 of the wellbore 102, thereby completing a circulation loop of the drilling fluid.

[0024] The wellsite 100 may also include a first (e.g., outlet) gas extractor 150 (also referred to as HC OUT). The outlet gas extractor 150 may be configured to extract at least a portion of the gas from the drilling fluid. The outlet gas extractor 150 may also or instead be configured to determine the hydrocarbon contribution in the drilling fluid based at least partially upon the extracted gas. In another embodiment, a computing system (described below) may be configured to determine the hydrocarbon contribution in the drilling fluid based at least partially upon the gas extracted by the outlet gas extractor 150.

[0025] The outlet gas extractor 150 may be positioned between the outlet 106 of the wellbore 102 and the shaker tank 136. In one embodiment, the outlet gas extractor 150 may be coupled to the outlet 106 of the wellbore 102. In another embodiment, the outlet gas extractor 150 may be coupled to and/or positioned at least partially within a line (e.g., pipe) 107 connecting the outlet 106 of the wellbore 102 to the shaker 130. In yet another embodiment, the outlet gas extractor 150 may be coupled to and/or positioned at least partially within the shaker 130. For example, the outlet gas extractor 150 may be positioned at least partially within the header box 132.

[0026] The wellsite 100 may also or instead include a second (e.g., inlet) gas extractor 160 (also referred to as HC IN). The inlet gas extractor 160 may be configured to extract at least a portion (e.g., a remaining portion) of the gas from the drilling fluid. The inlet gas extractor 160 may also or instead be configured to determine the hydrocarbon contribution in the drilling fluid based at least partially upon the extracted gas. In another embodiment, the computing system (described below) may be configured to determine the hydrocarbon contribution in the drilling fluid based at least partially upon the gas extracted by the inlet gas extractor 160.

[0027] The inlet gas extractor 160 may be positioned downstream from the outlet gas extractor 150. In one embodiment, the inlet gas extractor 160 may be positioned at least partially within the suction tank 140. In another embodiment, the inlet gas extractor 160 may be positioned at least partially within a line 141 connecting the suction tank 140 to the mud pump 120. In yet another embodiment, the inlet gas extractor 160 may be positioned at least partially between the mud pump 120 and the inlet 104 of the wellbore 102. For example, the inlet gas extractor 160 may be coupled to and/or positioned at least partially the standpipe 122, the hose 124, or the top drive 126. In yet another embodiment, the inlet gas extractor 160 may be coupled to and/or positioned at least partially within the inlet 104 of the wellbore 102. In yet another embodiment, which is described below, the inlet gas extractor 160 may be not functioning (e.g., temporarily out of service) or not present (i.e., the wellsite 100 and/or system may not include a second gas extractor).

[0028] The wellsite 100 may also include a first (e.g., outlet) sensor 170. The outlet sensor 170 may be configured to measure an outlet drilling fluid parameter. The outlet drilling fluid parameter may be or include an amount, a flow rate, and/or a level of the drilling fluid. The outlet sensor 170 may be positioned upstream and/or downstream from the outlet gas extractor 150. In one embodiment, the outlet sensor 170 may be or include a flow paddle and/or an ultrasonic sensorthat is positioned at least partially within the outlet 106 of the wellbore 102. In another embodiment, the outlet sensor 170 may be or include a flow paddle and/or an ultrasonic sensor that is positioned at least partially within the line 107 between the outlet 106 and the shaker 130. In yet another embodiment, the outlet sensor 170 may be or include a flow paddle and/or an ultrasonic sensorthat is positioned at least partially within the shaker 130 (e.g., the header box 132). The flow paddle or ultrasonic sensor may be configured to measure a flow rate of the drilling fluid flowing therepast. In yet another embodiment, the outlet sensor 170 may be or include a level sensor that is positioned at least partially in the shaker 130 (e.g., in the header box 132 and/or shaker tank 136) and configured to measure a fluid level of the drilling fluid therein.

[0029] The wellsite 100 may also include a second (e.g., inlet) sensor 180 positioned downstream from the outlet sensor 170. The inlet sensor 180 may be configured to measure an inlet drilling fluid parameter. The inlet drilling fluid parameter may also be or include an amount, a flow rate, and/or a level of the drilling fluid. In one embodiment, the inlet sensor 180 may be or include a level sensor that is positioned at least partially in the suction tank 140 and configured to measure a fluid level of the drilling fluid therein. In another embodiment, the inlet sensor 180 may be or include a flow paddle and/or an ultrasonic sensor that is positioned at least partially within the line 141 between the suction tank 140 and the mud pump 120. In yet another embodiment, the inlet sensor 180 may be or include a flow paddle and/or an ultrasonic sensor that is positioned at least partially within the mud pump 120. In yet another embodiment, the inlet sensor 180 may be or include a flow paddle and/or an ultrasonic sensor that is positioned at least partially within a line 121 between the mud pump 120 and the standpipe 122, within the standpipe 122, within the hose 124, or within the top drive 126. The flow paddle or ultrasonic sensor may be configured to measure a flow rate of the drilling fluid flowing therepast.

[0030] The wellsite 100 may also include a computing system 600 that may be configured to receive the measurements from the outlet gas extractor 150, the inlet gas extractor 160, the outlet sensor 170, the inlet sensor 180, or a combination thereof. For example, the computing system 600 may receive the measurements from the outlet gas extractor 150, the outlet sensor 170, and the inlet sensor 180. As described in greater detail below, the computing system 600 may be configured to determine the surface transit time for the drilling fluid to flow from the outlet sensor 170 to the inlet sensor 180.

[0031] The computing system 600 may also be configured to determine the hydrocarbon contribution downstream from the outlet gas extractor 150 and/or the outlet sensor 170 based at least partially upon the measured hydrocarbon contribution at the outlet gas extractor 150 and the surface transit time. For example, the computing system 600 may be configured to determine the hydrocarbon contribution of the drilling fluid in the suction tank 140, in the mud pump 120, and/or at the inlet sensor 180 based at least partially upon the measured hydrocarbon contribution at the outlet gas extractor 150 and the surface transit time.

[0032] The computing system 600 may also be configured to determine the actual hydrocarbon contribution in the drilling fluid from the subterranean formation 108 based at least partially upon the hydrocarbon contribution measured by the outlet gas extractor 150 and the determined hydrocarbon contribution downstream from the outlet gas extractor 150 (e.g., in the suction tank 140, in the mud pump 120, and/or at the inlet sensor 180).

[0033] Figure 2 illustrates a mud log from the wellsite 100 showing an increase in a flow rate measurement from the outlet sensor (e.g., a flow paddle sensor) 170, according to an embodiment. The mud log may be or include a field quality log, which is a real-time log from a mud logging unit at the wellsite 100. As shown, the measurements from the outlet sensor 170 are substantially constant when the mud pump 120 begins pumping the drilling fluid, as shown at 212. This is because the drilling fluid takes time before it reaches the outlet sensor 170. The measurements then begin increasing when the drilling fluid reaches and/or flows past the outlet sensor 170. This is a first time (also referred to as Tl).

[0034] Figure 3 illustrates a mud log from the wellsite 100 showing an increase in a fluid level measurement from an inlet sensor (e.g., a pit level sensor) 180, according to an embodiment. The mud log may be or include a field quality log, which is a real-time log from a mud logging unit at the wellsite 100. As shown, the measurements from the inlet sensor 180 begin decreasing when the mud pump 120 begins pumping the drilling fluid, as shown at 222. This is because the level of the drilling fluid in the suction tank 140 is decreasing. The measurements then become substantially constant or increase when the drilling fluid circulates around and reaches the inlet sensor 180 in the suction tank 140. This is a second time (also referred to as T2).

[0035] Figure 4 illustrates a table showing the data from Figures 2 and 3 in a different format (i.e., numerical rather than graphical), according to an embodiment. As shown in Figure 4, Tl occurs at 28: 15, and T2 occurs at 30:05. Thus, the surface transit time in this example is T2 (30:05) - Tl (28: 15) = 1 minute and 50 seconds.

[0036] Figure 5 illustrates a flowchart of a method for determining a hydrocarbon contribution, according to an embodiment. An illustrative order of the method 500 is provided below; however, one or more portions of the method 500 may be performed in a different order, combined, split into sub-portions, repeated, or omitted without departing from the scope of the disclosure. One or more portions of the method 500 may be performed by the computing system 600 described below with respect to Figure 6.

[0037] The method 500 may include pumping the drilling fluid into the wellbore 102, as at 502. More particularly, the mud pump 120 may pump the drilling fluid from the suction tank 140 through the standpipe 122, the hose 124, and the top drive 126. The drilling fluid may then flow into the wellbore 102 via the inlet 104. Once in the wellbore 102, the drilling fluid may flow down through the drill string 112 and out into the annulus via openings in the drill bit 110. The drilling fluid may then flow up through the annulus, where it may combine/mix with liquids, gases, and/or solids from the subterranean formation 108. The drilling fluid may then flow out of the wellbore 102 via the outlet 106.

[0038] The method 500 may also include measuring or receiving the outlet drilling fluid parameter, as at 504. The outlet drilling fluid parameter may be measured by the outlet sensor 170. As will be appreciated, it may take time (e.g., 38 minutes) for the drilling fluid to flow from the suction tank 140 to the outlet sensor 170. Thus, the measured outlet drilling fluid parameter may be less than a predetermined outlet drilling fluid parameter threshold (e.g., 1 liter/second) during this time. [0039] The method 500 may also include determining a time when the outlet drilling fluid parameter increases, as at 506. More particularly, once the drilling fluid reaches the outlet sensor 170, the measured outlet drilling fluid parameter may become greater than the predetermined outlet drilling fluid parameter threshold. This time may be referred to as a first time or Tl. This is illustrated in Figure 2.

[0040] The method 500 may also include measuring or receiving the inlet drilling fluid parameter, as at 508. The inlet drilling fluid parameter may be measured by the inlet sensor 180. In an embodiment where the inlet sensor 180 is a level sensor in the suction tank 140, the measured inlet drilling fluid parameter may initially decrease from the time that the mud pump 120 begins pumping the drilling fluid until the time that the drilling fluid reaches the inlet sensor 180. In an embodiment where the inlet sensor is a flow paddle or ultrasonic sensor configured to measure flow rate, the measured inlet drilling fluid parameter may initially remain substantially constant from the time that the mud pump 120 begins pumping the drilling fluid until the time that the drilling fluid reaches the inlet sensor 180. Thus, the measured inlet drilling fluid parameter may be less than a predetermined inlet drilling fluid parameter threshold during this time. [0041] The method 500 may also include determining a time when the inlet drilling fluid parameter becomes substantially constant or increases, as at 510. More particularly, once the drilling fluid circulates and reaches the inlet sensor 180, the measured inlet drilling fluid parameter may become equal to or greater than the predetermined inlet drilling fluid parameter threshold. This time may be referred to as a second time or T2. This is illustrated in Figure 3.

[0042] The method 500 may also include determining the surface transit time (STT) of the drilling fluid, as at 512. The surface transit time may be determined based at least partially upon the first time (Tl) and the second time (T2):

STT = T2 - Tl Equation (1)

This is shown in Figure 4.

[0043] The method 500 may also include extracting a portion of the gas from the drilling fluid, as at 514. As mentioned above, the gas may be extracted by the outlet gas extractor 150, the inlet gas extractor 160, or both. For example, the gas may be extracted by the outlet gas extractor 150, and the inlet gas extractor 160 may be omitted.

[0044] The method 500 may also include measuring or determining the outlet hydrocarbon contribution in the drilling fluid, as at 516. Continuing with the example above, the outlet hydrocarbon contribution in the drilling fluid may be measured or determined in the portion of the gas extracted by the outlet gas extractor 150. The outlet hydrocarbon contribution may also be referred to as the measured hydrocarbon contribution.

[0045] The method 500 may also include determining the inlet hydrocarbon contribution in the drilling fluid, as at 518. Continuing with the example above, the inlet hydrocarbon contribution in the drilling fluid may be determined proximate to the location where the second time (T2) is determined (e.g., in the suction tank 140). The inlet hydrocarbon contribution may also be referred to as the determined hydrocarbon contribution. The inlet hydrocarbon contribution may be determined based at least partially upon the outlet hydrocarbon contribution and the surface transit time.

[0046] The method 500 may also include determining the actual hydrocarbon contribution in the drilling fluid, as at 520. The actual hydrocarbon contribution may be determined by: actual hydrocarbon contribution = outlet hydrocarbon contribution - inlet hydrocarbon contribution (Equation 2)

[0047] The method 500 may also include displaying the outlet drilling fluid parameter, the time when the outlet drilling fluid parameter increases, the inlet drilling fluid parameter, the time when the inlet drilling fluid parameter becomes substantially constant or increases, the surface transit time of the drilling fluid, the outlet hydrocarbon contribution, the inlet hydrocarbon contribution, the actual hydrocarbon contribution, or a combination thereof, as at 522. Examples of this are shown in Figures 2-4.

[0048] The method 500 may also include determining or performing a wellsite action, as at 524. The wellsite action may be determined or performed based at least partially upon the surface transit time, the inlet hydrocarbon contribution, the actual hydrocarbon contribution, or a combination thereof. In one embodiment, performing the wellsite action may include generating and/or transmitting a signal (e.g., using the computing system 600) which instructs or causes a physical action to take place. In another embodiment, performing the wellsite action may include physically performing the action (e.g., either manually or automatically). Illustrative physical actions may include, but are not limited to, calibrating, repairing, and/or replacing the gas extractor 150, the outlet sensor 170, the inlet sensor 180, or a combination thereof. Other physical actions may include, but are not limited to, drilling the wellbore 102, varying a trajectory of the wellbore 102, producing the hydrocarbons from the wellbore 102, varying a speed of the mud pump 120 (and/or a flow rate of the drilling fluid), varying a composition of the drilling fluid, or a combination thereof.

[0049] The method 500 may estimate or determine the surface transit time, the inlet hydrocarbon contribution, and/or the actual hydrocarbon contribution at any stage of circulation and/or for any flow rate. In one embodiment, the method 500 may be performed while there are minimal (e.g., zero) losses on the surface and/or downhole. The method 500 may also be performed while there are minimal (e.g., zero) transfers into and/or out of the tanks 136, 140. In addition, the flow rate of the drilling fluid through the circulation path may remain substantially constant during the method 500 (e.g., at least until the drilling fluid reaches the suction tank 140). If the suction tank 140 is a plurality of tanks/pits, then the second time T2 may be measured in the first tank/pit.

[0050] The method 500 may help to generate a dataset while the second (e g., inlet) gas extractor 160 is not functioning or not present. This may facilitate decision-making at the wellsite 100. The dataset may also lead to higher quality data, which may be useful if/when the inlet gas extractor 160 becomes present and/or functioning. In one embodiment, the data acquisition frequency may be about 80% from the outlet gas extractor 150 and about 20% from the inlet gas extractor 160 when the inlet gas extractor 160 is present and/or functioning. The data acquisition frequency may be about 100% from the outlet gas extractor 150 and 0% from the inlet gas extractor 160 when the inlet gas extractor 160 is not present and/or not functioning.

[0051] In one embodiment, the method 500 may be implemented if/when the inlet gas extractor 160 is (e.g., temporarily) out of service (e.g., for maintenance). Thus, the method 500 may serve as a backup technique to determine the inlet hydrocarbon contribution and/or the actual hydrocarbon contribution. The method 500 also improves sustainability. For example, the method 500 may allow for the omission of the inlet gas extractor 160, which reduces the hardware, installation time, and electricity consumption at the wellsite 100. In one embodiment, the method 500 may also include determining a solids accumulation in the sand trap without using a dedicated sensor to measure the solids accumulation. For example, when the solids accumulate in the sand trap at a steady flow rate, the surface transit time decreases.

[0052] In some embodiments, the methods of the present disclosure may be executed by a computing system. Figure 6 illustrates an example of such a computing system 600, in accordance with some embodiments. The computing system 600 may include a computer or computer system 601A, which may be an individual computer system 601A or an arrangement of distributed computer systems. The computer system 601A includes one or more analysis modules 602 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module 602 executes independently, or in coordination with, one or more processors 604, which is (or are) connected to one or more storage media 606. The processor(s) 604 is (or are) also connected to a network interface 607 to allow the computer system 601 A to communicate over a data network 609 with one or more additional computer systems and/or computing systems, such as 601B, 601C, and/or 601D (note that computer systems 601B, 601C and/or 601D may or may not share the same architecture as computer system 601A, and may be located in different physical locations, e.g., computer systems 601 A and 601B may be located in a processing facility, while in communication with one or more computer systems such as 601C and/or 601D that are located in one or more data centers, and/or located in varying countries on different continents).

[0053] A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.

[0054] The storage media 606 may be implemented as one or more computer-readable or machine- readable storage media. Note that while in the example embodiment of Figure 6 storage media 606 is depicted as within computer system 601A, in some embodiments, storage media 606 may be distributed within and/or across multiple internal and/or external enclosures of computing system 601A and/or additional computing systems. Storage media 606 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLURAY® disks, or other types of optical storage, or other types of storage devices. Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). An article or article of manufacture may refer to any manufactured single component or multiple components. The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution. ‘

[0055] In some embodiments, computing system 600 contains one or more hydrocarbon contribution module(s) 608 configured to perform at least a portion of the method 500. It should be appreciated that computing system 600 is merely one example of a computing system, and that computing system 600 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of Figure 6, and/or computing system 600 may have a different configuration or arrangement of the components depicted in Figure 6. The various components shown in Figure 6 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.

[0056] Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general- purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are included within the scope of the present disclosure. [0057] Computational interpretations, models, and/or other interpretation aids may be refined in an iterative fashion; this concept is applicable to the methods discussed herein. This may include use of feedback loops executed on an algorithmic basis, such as at a computing device (e.g., computing system 600, Figure 6), and/or through manual control by a user who may make determinations regarding whether a given step, action, template, model, or set of curves has become sufficiently accurate for the evaluation of the subsurface three-dimensional geologic formation under consideration.

[0058] As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “upstream” and “downstream”; “above” and “below”; “inward” and “outward”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.” [0059] The foregoing description, for purposes of explanation, used specific nomenclature to provide a thorough understanding of the disclosure. However, it will be apparent to one skilled in the art that the specific details are not required in order to practice the systems and methods described herein. The foregoing descriptions of specific examples are presented for purposes of illustration and description. They are not intended to be exhaustive of or to limit this disclosure to the precise forms described. Many modifications and variations are possible in view of the above teachings. The examples are shown and described in order to best explain the principles of this disclosure and practical applications, to thereby enable others skilled in the art to best utilize this disclosure and various examples with various modifications as are suited to the particular use contemplated. It is intended that the scope of this disclosure be defined by the claims and their equivalents below.