The present disclosure relates to artificial lift systems that inject gas into production tubing of hydrocarbon production wells. More specifically, a process is provided that allows for dynamically adjusting (e.g., increase or decrease) a gas injection rate to identify a rate that yields a near peak bottom hole pressure drawdown and/or total fluid production.
Well bores of oil and gas wells extend from the surface to permeable subterranean formations (‘reservoirs’) containing hydrocarbons. These well bores are drilled in the ground to a desired depth and may include horizontal sections as well as vertical sections. In any arrangement, piping (e.g., steel), known as casing, is inserted into the well bore. The casing may have differing diameters at different intervals within the well bore and these various intervals of casing may be cemented in-place. Other portions (e.g., within producing formations) may not be cemented in place and/or include perforations to allow hydrocarbons to enter into the casing. Alternatively, the casing may not extend into the production formation (e.g., open-hole completion).
Disposed within a well casing is a string of production piping/tubing, which has a diameter that is less than the diameter of the well casing. The production tubing may be secured within the well casing via one or more packers, which may provide a seal between the outside of the production piping and the inside of the well casing. The production tubing provides a continuous bore from the production zone to the wellhead through which oil and gas can be produced.
The flow of fluids, from the reservoir(s) to the surface, may be facilitated by the accumulated energy within the reservoir itself, that is, without reliance on an external energy source. In such an arrangement, the well is said to be flowing naturally. When an external source of energy is required to flow fluids to the surface the well is said to produce by a means of artificial lifting. Generally, this is achieved by the use of a mechanical device inside the well (e.g., pump) or by decreasing the weight of the hydrostatic column in the production tubing by injecting gas into the liquid some distance down the well.
The injection of gas to decrease the weight of a hydrostatic column is commonly referred to as gas lift, which is artificial lift technique where bubbles of compressed air/gas are injected to reduce the hydrostatic pressure within the production tubing to below a pressure at the inlet of the production tubing. In one gas lift arrangement, high pressure gas is injected into the annular space between the well casing and the production tubing. At one or more predetermined locations along the length of the production tubing, gas lift valves permit the gas in the annular space to enter into the production tubing. Such a gas lift artificial lift system may be combined with additional artificial lift systems. For instance, gas lift may be combined with plunger lift in some arrangements.
Presented herein are systems, methods and processes (i.e., utilities) for enhancing or optimizing the gas injection setpoint of a well utilizing gas lift. Generally, the utilities includes initiating a gas lift at an initial gas injection rate or setpoint. The utility utilizes inputs associated a bottom hole pressure to subsequently adjust the gas injection rate. Such inputs may be acquired from, for example, a bottom hole pressure sensor and/or a production rate sensor. In the former regard, a dedicated bottom hole pressure sensor monitors a bottom hole pressure drawdown rate. In the latter regard, a production rate sensor allows for substituting the bottom hole pressure with a total fluid production rate. In further embodiments, the bottom hole pressure may be inferred. For instance, when a dedicated sensor is not available to monitor (e.g., directly or indirectly) bottom hole pressure, the bottom hole pressure may be inferred from known well data and one or more variables (e.g., well depth, formation depth, casing size, temperature etc.) that are known or may be measured. By way of example, performance of a multiphase correlation calculation may provide an input associated with a down hole pressure. Various multiphase correlations are known including, without limitation, Hagedorn and Brown, Petroleum Experts, Petroleum Experts 2, Petroleum Experts 3, Fancher Brown, and Beggs and Brill, to name a few.
In any arrangement, the utilities control a gas injection flow valve and/or source of injection gas (e.g., gas injection compressor) to increase or decrease a gas injection flow rate into the well during a gas injection interval. In an arrangement, an initial injection rate (e.g., gas injection setpoint) is maintained for a predetermined interval. Based on this injection rate an initial bottom hole pressure (e.g., first BHP) is determined for the interval. The gas injection rate or setpoint is then either increased or decreased a predetermined amount for another time gas injection interval. A subsequent average bottom hole pressure is obtained (e.g., second BHP). At the initiation of the process, the gas injection rate is then increased or decreased in the same direction as the previous increase or decrease for another gas injection interval to find a further bottom hole pressure (e.g., third BHP). The difference or change between the first BHP and second BHP is compared with difference of change between the second BHP and the third BHP. This changes correspond to a Bottom Hole Pressure Drawdown (BHPD) rate. If the second drawdown rate is greater than the first drawdown rate, the direction of change in the injection rate is trending toward a more optimal setting and further increases or decreases in the same direction are applied to the gas injection rate. If the second drawdown rate is less that the first drawdown rate, the injection rate is being adjusted in the incorrect direction and the process reverses. The process may continue in a loop further adjusting the gas injection rate to iterate to closer an optimal setting. That is, after initiation of the process, a new or subsequent BHPD is compared to the prior/previous BHPD to determine a subsequent adjustment direction and/or magnitude for a subsequent gas injection rate. However, in various arrangements, the process may be interrupted and/or altered based on one or more predetermined factors.
Reference will now be made to the accompanying drawings, which at least assist in illustrating the various pertinent features of the present disclosure. The following description is presented for purposes of illustration and description and is not intended to limit the disclosed embodiments to the forms disclosed herein. Consequently, variations and modifications commensurate with the following teachings, and skill and knowledge of the relevant art, are within the scope of the present disclosure.
Control valve—An electronic actuating valve that moves open and close based on an external input
Bottom Hole Pressure (BHP)—A pressure value that is indicative of a pressure at the bottom of a well.
Gas injection setpoint—Gas injection rate into an well bore.
Optimal Gas injection Setpoint—Gas injection rate that yields the greatest BHP drawdown or total fluid production.
Unloading—Increasing Gas Injection that produces a higher BHP delta
Loading—Decreasing Gas injection that produces a lower BHP delta
Drawdown—Decreasing Gas injection to produce a higher BHP delta
Build Up—Increasing Gas injection that produces a lower BHP delta
The following disclosure is directed to a process for optimizing a gas injection rate to maximize total fluid production of a well, which typically corresponds to the maximized bottom hole drawdown.
After being drilled and completed, well production typically declines over time. This decline can be defined as depleting gas and fluid production rates which are directly related to the reduction in reservoir pressure.
In operation, a high-pressure source of gas (not shown) is injected into the well casing in the annulus between the well-casing 10 and the production tubing 12. The gas lift valves 22 supported by each mandrel 20 opens as the injection gas displaces fluid from the annulus. As these valves open, the opened valve injects gas from the annulus into production tubing 12 via valve port(s) 18 in the mandrel 20. See
Aspects of the present disclosure are directed to adjusting the rate at which pressurized gas is injected into the well in the annulus in the annulus between the well-casing and the production tubing. When using gas gift as a means of artificial lift, the Gas Injection Rate (GIR) is a key contributor to successful producing of the well. As noted, gas is compressed and injected through a series of valves such that the gas enters the production tubing along with reservoir fluids and formation gas.
The present disclosure is directed to determining a near optimal gas injection rate that will result in reducing a bottom hole pressure and/or enhancing the rate of bottom hole pressure drawdown. By monitoring or otherwise estimating a bottom hole pressure based on available data, a near optimal gas injection rate may be iteratively determined by increasing or decreasing gas injection rates to determine which injection rate yields the greatest rate of reduction of the bottom hole pressure (e.g., Bottom Hole Pressure Drawdown or BHPD). By tracking the different injection rates (e.g., injection rate setpoints) and comparing the results for each injection rate setpoint to previous injection rate setpoints, a trend can be developed which will indicate whether the current injection rate setpoint is above or below an optimal gas injection rate. Accordingly, the current injection rate setpoint may be adjusted to be nearer the optimal gas injection rate.
A practical example of the concepts shown in
The automated process (e.g., hunting process) of determining a near optimal gas injection rate uses several different inputs that are subsequently ran through a calculation to determine what the next output (i.e., gas injection rate setpoint) will be to eventually determine a near optimal gas injection setpoint. The hunting process is executed in an electronic controller\RTU\PLC or other processing device. The configuration, status, and results of the process may be made available to a remote terminal via a communications connection (e.g., via wireline or wireless communications) where an operator can review the data. Modifications to the configuration may be made remotely through the same connection.
Surface control equipment includes a master valve(s) 14 and a production line 16. The master valve 14 allows for opening and closing the well. In an embodiment, the master valve may operate in response to instructions from a well controller 40. The controller may operate the well based on time, pressure or based on operator-determined requirements for production. Alternatively, the controller may fully automate the production process. In the illustrated embodiment, the surface control equipment also includes the gas injection line 30, a gas injection control valve 32, a gas injection flow meter 34 and a source of injection gas. In the present embodiment, the source of injection gas is a compressor 36, which may compress available production gases (e.g., pipeline gases) in fluid connection (not shown) with the compressor. The gas injection flow valve 32 may be any electronic actuating valve that moves open and close based on an external input (e.g., valve control signal from the controller 40).
The controller 40, in the illustrated embodiment, is in data communication with either or both a bottom hole pressure gauge 42 and a production flow sensor 44. Information from these sensing devices may be used as an input in the hunting process. In this regard, the bottom hole pressure gauge 42 and/or the production flow sensor may generate an output that is indicative of a bottom hole pressure of the well. These outputs may be used to monitor bottom hole pressure drawdown for gas injection rate adjustment. However, it will be appreciated, that the bottom hole pressure may be otherwise measured or inferred. For instance, when a dedicated sensor is not available to monitor bottom hole pressure, the bottom hole pressure may be inferred from known well data and one or more variables (e.g., well depth, formation depth, casing size, temperature etc.) that are known to the controller and/or measured. By way of example, performance of a multiphase correlation calculation may provide an input associated with a down hole pressure. Various multiphase correlations are known including, without limitation, Hagedorn and Brown, Petroleum Experts, Petroleum Experts 2, Petroleum Experts 3, Fancher Brown, and Beggs and Brill, to name a few. Further, the controller 40 is in communication with the gas injection flow meter 34 to determine the rate that gas is being injected into the well (gas injection rate). The flow meter may be any electronic device that measures gas flow/volumes. In an embodiment, the flow meter measures gas flow through an orifice. The gas injection rate forms an input for the hunting process. The controller is also in communication with the gas injection control valve 32. The controller generates an output that adjusts the valve 32 to increase or decrease the gas injection flow (e.g., flow rate) into the well.
The controller 40 can include or perform functionality of the hunting process in addition to controlling the various valve and equipment at the well head. Alternatively, these function may be distributed between two or more controllers or processing platforms (not shown). Generally, the controller 40 may include various hardware elements and software elements. The hardware elements can include one or more processing units, one or more input devices (e.g., a keypad, modem etc.). The controller can also include one or more storage devices such as, by way of example, solid-state storage devices, random access memory (RAM) and/or a read-only memory (ROM) etc. The controller 40 can additionally include a communications system (e.g., a modem, a network card (wireless or wired), an infra-red communication device, etc.), and working memory, which can include RAM and ROM. The communications system can permit data to be exchanged with a network and/or a remote terminal 50. The controller 40 can also include software elements. In some embodiments, one or more functions of the hunting process are implemented as application code in working memory of the controller.
The new gas injection setpoint is maintained 113 for another time interval or step. After the time interval, a third bottom hole average pressure (e.g., third average BHP) is established 114 and the interval timer is reset 115. The third average BHP is then subtracted from the second average BHP (i.e., the previous BHP) to determine 116 an updated current BHPD (e.g., second drawdown rate). A determination 118 is made regarding the change in the drawdown rates. If the second drawdown rate is greater than the first drawdown rate, the bottom hole pressure is continuing to decrease and the adjustment is proceeding in the correct direction and further adjustment is made in that direction. Continuing with the present example, if the second drawdown rate is greater than the first drawdown rate, the gas injection setpoint (e.g., adjusted gas injection setpoint) is again increased 120, for example from 425 MCF to 475 MCF. In contrast, if the second drawdown is less than the first drawdown rate, the adjustment is proceeding in the wrong direction. In such a situation, the gas injection setpoint (e.g., adjusted gas injection setpoint) is decreased 122 at one-half of the previous adjustment step. In the case of the above example, the gas injection setpoint would decrease 25 MCF (e.g., a half adjustment or other fractional adjustment in the opposite direction) from 425 to 400. In either case, the loop continues for successive time intervals/steps where a gas injection rate is maintained 123 for a new interval and a new or current average BHP is calculated 114 for that interval. The current average BHP is then subtracted from the previous average BHP to establish a new or current BHPD, which is compared to the previous BHPD such that the gas injection rate may be further adjusted. Of note, adjustment of the gas injection rate in the same direction as the previous adjustment set forth above for the first two intervals is only required at the start of the process. After a first BHPD is established, the process may utilize any two BHPD to make subsequent adjustments without regard to successive adjustments being in the same direction.
The result of the hunting process set forth in
The graph of
The process illustrated in
At this point in the process 100A, a determination is made regarding the magnitude of the current BHPD. Specifically, the current BHPD rate is compared 124 to a predetermined threshold. This threshold, referred to as the “Force Increase Threshold” in
Table 2 illustrates an exemplary set of well data wherein an initial GIR at kickoff is 500 MCF, a Maximum GIR adjustment (GIR ADJ) is 50 MFC and a Force Increase Threshold is 2 psi.
In the example of Table 2, where the Force Increase Threshold is set as 2 psi., any change in the BHP delta that exceeds the 2 psi threshold will result in an automatic max increase to the gas injection setpoint regardless of the previous step adjustment direction. As shown, at step 6, proceeding an increase of 25 MCF in the GIR at step 5, the result was a BHP delta of 3 psi. As the BHP in step 6 was greater than the Force Gas injection Increase Threshold of 2 psi, the GIR adjustment to made for Step 7 is an increase to the GIR of 50 MCH, which equivalent to the max adjustment. Due to BHP Delta of Step 7 BHP delta being less than the Force Increase Threshold, the normal process or algorithm continues to run and a GIR increase is derived for Step 8 given the BHP of Step 7 is less than both the result of Step 6 and the Force Increase Threshold. The use of the Force Increase Threshold helps prevent the increase in bottom hole pressure, which may reduce production from the well.
As noted above, there may be times during production of a well where insufficient gas may be available for injection. That is, production gases from the well or nearby wells or pipelines are often utilized as the source of injection gas for artificial lift. At times, insufficient amounts of these gases may be available for injection.
As shown, the process (e.g., as implemented in the controller) periodically obtains 302 a current gas injection rate. The current gas injection rate may be a real-time reading of the rate that gas is being injected at surface into the well. Such current readings may be taken at user defined intervals. The current gas injection rate is compared 304 to a minimum gas injection rate setpoint or threshold. If the current gas injection rate exceeds the minimum gas injection rate threshold or setpoint, the hunting process 306 continues unabated until the next current gas injection rate is read and compared to the threshold. If the current gas injection rate falls below the defined setpoint/threshold, the process 300 enters a gas injection rate failure subroutine 308. At this time, the process stops the hunting algorithm/process and monitors the current gas injection rate 310. Such monitoring continues 312 until the available gas (e.g., current gas injection rate) exceeds the current gas injection setpoint (e.g., as previously determined by the hunting algorithm). Once the current gas injection rate is sufficient, the hunting algorithm/process interval and BHP averages are reset 314 and the gas injection continues at the last gas injection rate setpoint. Stated otherwise, should the Current Gas injection rate fall below the threshold, the data being averaged for the purpose of the hunting algorithm during that interval is thrown out and the hunting algorithm does not start a new interval until the current gas injection rate reaches the current gas injection rate set point. Once the current gas injection rate reaches the gas injection set point a new interval is started and the normal operation of the hunting algorithm commences.
Table 3 illustrates data for two intervals where a gas injection rate falls below a predetermined minimum. In the presented example the interval length is 24 hours with readings taken every hour and a minimum gas injection threshold of 300 MCF.
As set forth in Table 3, numerous readings are omitted for purposes of presentation. Initially, Interval 1 starts at 8:00 with a GIR Setpoint of 500 MCF and BHP of 2000 psi. Every hour (or other sub-interval) the actual GIR is measured as is the bottom hole pressure. Of note, the actual GIR may vary from the GIR Setpoint. In this example, Interval 1 proceeds without the actual GIR falling below the minimum gas injection threshold. At the end of Interval 1 at 7:59 (i.e., next day), the BHP average is calculated from all of the readings, a BHP Delta is calculated and a GIR ADJ of +50 MCF is made to the GIR setpoint. Thus, Interval 2 starts with a GIR Setpoint of 550 MCF and a BHP Average of 1988.33. At 18:00, ten hours into Interval 2, the actual GIR (available gas) drops to 123 MFC, which is below the minimum gas injection threshold of 300 MCF. Thus, the process of
The foregoing description has been presented for purposes of illustration and description. Furthermore, the description is not intended to limit the disclosed embodiments to the forms disclosed herein. Consequently, variations and modifications commensurate with the above teachings, and skill and knowledge of the relevant art, are within the scope of the present disclosure. The embodiments described hereinabove are further intended to explain best modes known of practicing the disclosed processes and to enable others skilled in the art to utilize these processes in such, or other embodiments and with various modifications required by the particular application(s) or use(s) of the presented disclosure. It is intended that the appended claims be construed to include alternative embodiments to the extent permitted by the prior art.
The present application claims the benefit of the filing date of U.S. Provisional Application No. 62/674,160 having a filing date of May 21, 2018, the entire contents of which is incorporated herein by reference.
Number | Date | Country | |
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62674160 | May 2018 | US |