Patent Application
20190376355
This invention pertains generally to technology for monitoring the drilling fluid while drilling a well to extract fluid deposits from subterranean formations (e.g., oil, gas, water). More specifically, systems and methods are provided for real-time monitoring of drilling fluid including at or near the point the drilling fluid returns to the surface with cuttings (e.g., at the bell nipple).
As is well known in the art, drilling fluids are used for a variety of purposes in drilling operations. Drilling fluid (aka drilling mud) is typically pumped into the drilled hole (the borehole) through the drill pipe and bit and the fluid returns to the surface in the annulus between the drill pipe and the borehole wall. The drilling fluid serves to, for example, cool and lubricate the drill bit, return drill cuttings to the surface, keep subterranean fluids from escaping through the borehole to reach the surface (pressure control), and to mechanically stabilize the borehole wall.
The drilling fluid's ability to return drill cuttings to the surface is a function of a variety of factors including the viscosity of the drilling fluid in the borehole, the cuttings size and density, and the rate at which the drilling fluid is circulated (the mud flow rate). (This list of factors is not meant to be exhaustive.) Failure to properly remove the cuttings may, for example, result in the drill pipe sticking in the hole. The viscosity of the drilling fluid in the borehole is a function of the viscosity of the fluid pumped into the borehole and the drill cuttings carried in the fluid
The drilling fluid's pressure-control capability is a function of a variety of factors including the density of the drilling fluid in the borehole, the size and shape of the return annulus, and the rate at which the drilling fluid is circulated. (This list of factors is not meant to be exhaustive.) For example, the higher the density of the drilling fluid, the more pressure it exerts on the borehole walls (and the pressure increases with vertical depth). If, at a particular depth in the borehole, the pressure of the drilling fluid is less than the pore pressure, formation fluids can escape to the surface and the well will “kick” potentially dangerous fluids. This can lead to catastrophic consequences. If the pressure of the drilling fluid is greater than the formation's fracture pressure, the formation may fracture and drilling fluid may escape into the formation. This may result in a reduced drilling-fluid pressure (which can lead to kicks) and loss of returns to the surface. It is important to maintain the drilling fluid pressure at the proper level for the formation conditions. Thus, it is important to have the appropriate drilling-fluid density for formation, drilling, and circulating conditions.
The density of the drilling fluid in the borehole is a function of the density of the fluid pumped into the borehole and the drilling cuttings carried in the fluid (along with other factors, such as formation fluids that enter the borehole fluid). Typically, cuttings are removed (if only partially) from the drilling fluid that returns to the surface before the drilling fluid is pumped back into the drill pipe. Measurements of drilling-fluid density are typically done after the cuttings are removed and thus provide imperfect information about the downhole drilling-fluid density.
Accordingly, there is a need for drilling-fluid-monitoring technology to provide better information regarding drilling-fluid conditions at various points in the drilling-fluid circulation system.
Circulation-system instrumentation according to the invention supplies information to drilling-rig operators (e.g., drillers, engineers) about the status and trends of drilling fluid in the circulation system. This information can be used by the operators to control the circulation system to better ensure safe and efficient drilling operations.
In one aspect of the invention, a drilling-fluid-circulation pipe configured to be installed to or as the bell nipple includes two pressure sensors. The sensors are vertically separated when the pipe is installed in the circulation system and are configured to provide two measures of drilling fluid pressure while drilling operations are proceeding. The sensors thus provide real-time information regarding the density of the drilling fluid returned to the surface before cuttings are removed from the fluid. In another aspect of the invention, the pipe includes viscosity sensors to provide real-time monitoring of the viscosity of the drilling fluid returned to the surface before cuttings are removed from the fluid. A drilling-fluid temperature sensor may be included (separate or as part of one of the other sensors).
In another aspect of the invention, pairs of vertically separated pressure sensors may be installed at other points in the circulation system to provide real-time monitoring of the circulating-drilling-fluid density. For example, a pair of sensors may be installed at the bell nipple to monitor drilling fluid returned from the borehole with cuttings. And a pair of sensors may be installed at the processing pit to monitor drilling fluid below the shale shaker. And a pair of sensors may be installed at the suction pit to monitor drilling fluid just before it is pumped into the well. These sensors provide real-time drilling-fluid information at various points in the circulation system and thus provide a better monitor of the status of the circulation system.
In another aspect of the invention, a method of monitoring a drilling-fluid circulation system includes collecting pressure information from a pair of vertically separated pressure sensors, calculating a difference in pressure between the two sensors, and using the pressure difference to infer information about the level and density of the drilling fluid. The density or level information is compared with predetermined density or level information to determine trends or problems in the circulation system. For example, the density from the pressure differential may be compared to a target density, to a previously determined pressure-differential density, or to density at another point in the circulation system. These comparisons can be used to determine whether to modify the circulation system (e.g., to seal the well to prevent a kick or to add solids or fluids to the drilling fluid).
These and other features, aspects, and advantages of the present invention will become better understood with reference to the following description, appended claims, and accompanying drawings where:
In the summary above, and in the description below, reference is made to particular features of the invention in the context of exemplary embodiments of the invention. The features are described in the context of the exemplary embodiments to facilitate understanding. But the invention is not limited to the exemplary embodiments. And the features are not limited to the embodiments by which they are described. The invention provides a number of inventive features which can be combined in many ways, and the invention can be embodied in a wide variety of contexts. Unless expressly set forth as an essential feature of the invention, a feature of a particular embodiment should not be read into the claims unless expressly recited in a claim.
Except as explicitly defined otherwise, the words and phrases used herein, including terms used in the claims, carry the same meaning they carry to one of ordinary skill in the art as ordinarily used in the art.
Because one of ordinary skill in the art may best understand the structure of the invention by the function of various structural features of the invention, certain structural features may be explained or claimed with reference to the function of a feature. Unless used in the context of describing or claiming a particular inventive function (e.g., a process), reference to the function of a structural feature refers to the capability of the structural feature, not to an instance of use of the invention.
Except for claims that include language introducing a function with “means for” or “step for,” the claims are not recited in so-called means-plus-function or step-plus-function format governed by 35 U.S.C. § 112(f). Claims that include the “means for [function]” language but also recite the structure for performing the function are not means-plus-function claims governed by § 112(f). Claims that include the “step for [function]” language but also recite an act for performing the function are not step-plus-function claims governed by § 112(f).
Except as otherwise stated herein or as is otherwise clear from context, the inventive methods comprising or consisting of more than one step may be carried out without concern for the order of the steps.
The terms “comprising,” “comprises,” “including,” “includes,” “having,” “haves,” and their grammatical equivalents are used herein to mean that other components or steps are optionally present. For example, an article comprising A, B, and C includes an article having only A, B, and C as well as articles having A, B, C, and other components. And a method comprising the steps A, B, and C includes methods having only the steps A, B, and C as well as methods having the steps A, B, C, and other steps.
Terms of degree, such as “substantially,” “about,” and “roughly” are used herein to denote features that satisfy their technological purpose equivalently to a feature that is “exact.” For example, a component A is “substantially” perpendicular to a second component B if A and B are at an angle such as to equivalently satisfy the technological purpose of A being perpendicular to B.
Except as otherwise stated herein, or as is otherwise clear from context, the term “or” is used herein in its inclusive sense. For example, “A or B” means “A or B, or both A and B.”
In the typical desired operation, the drilling fluid that returns to the surface will include cuttings created by the drill bit 118 as it penetrates the earth. The returned drilling fluid—with cuttings—flows out the bell nipple 106 through the flow line 122 to the drilling-fluid processing system 124. The drilling-fluid processing system 124 cleans the drilling fluid by, among other things, removing the cuttings (at least partially). For example, the returned drilling fluid is run over a shale shaker 124a that removes coarse cuttings from the drilling fluid which is then contained in a processing pit 124b until further processed. (In the context of the circulation system, “pit” and “tank” are used synonymously. That is, a pit may be a fluid-containing hole dug in the ground, it may also be a container constructed of, for example, steel.) The drilling fluid may be further cleaned and processed through various components 124c, such as hyrdrocyclones, mud cleaners, and centrifuges. The cleaned drilling fluid is eventually contained in a suction pit 124d. The drilling fluid may be further processed by addition of products via a hopper 124e. A pump 126 moves fluid from the suction pit 124d through a hose 120 back through the drill pipe 112 and out the drill bit 118.
The difference in pressure readings at the two sensors 302, 304 is indicative of the density of the drilling fluid in the bell nipple and can be used to estimate the height of the drilling-fluid surface above either of the sensors 302, 304 (the drilling-fluid surface is shown in the figure as a dashed line 308).
Where k1 is a factor that depends on gravity and the vertical separation of the sensors and k2 is a factor that depends on gravity. The height above the sensor can be used to estimate the rate the drilling fluid flows into the flow line 122. For example, the flow rate through the flow line 122 can be estimated based on the Manning equation because the height of the fluid 308 provides a measure of the cross-sectional area of drilling-fluid in the flow line (because the distance between the flowline and the pressure sensors 302, 304 is known).
The measure of density of the drilling fluid in the bell nipple provides an indication of the downhole density of the drilling fluid in the annulus between the drill pipe 112 and the borehole wall 114. This can be used to determine the equivalent circulating density (ECD) which is a measure of the pressure exerted by the drilling fluid on the borehole wall 114.
Variance of density of the drilling fluid in the bell nipple as compared to previously measured densities or to the density of the drilling fluid at other points in the circulation system provide information about the status of the circulation system. For example, a decrease in bell-nipple drilling-fluid density may indicate an influx of formation fluid deposits (e.g., natural gas, water, or oil). This can indicate the circulation system is underbalanced: the pressure exerted by the drilling-fluid density is not sufficient to keep the formation fluids from entering the borehole and returning to surface. This could presage a dangerous well kick. Similarly, an increase in bell-nipple drilling-fluid density may indicate increased cuttings. This could indicate a washout or similar condition in which the borehole wall is collapsing and the integrity of the well is at risk.
The bell-nipple drilling-fluid monitor may also include an inline viscosity sensor 306. The viscosity sensor 306 is installed on the bell nipple 106 and is configured to provide a measure of viscosity of drilling fluid in the bell nipple 106. Variance in the viscosity (e.g., over time, compared to other points in the circulation system, compared to target) can indicate changing conditions. For example, certain cuttings may react with the injected drilling fluid to lower its viscosity. This lowers the drilling fluid's ability to return the cuttings to the surface and can jeopardize the entire drilling operation (e.g., sticking of the drill pipe in the borehole due to unremoved cuttings near the drill bit). (The viscosity sensor is depicted as a separate device, but it may equivalently be part of a pressure-sensor device.)
In the depicted exemplary embodiment, the bell-nipple drilling-fluid monitor has sensors installed on the bell nipple. Equivalently, the sensors may be installed on a pipe (tube) that attaches to the bell nipple and is part of the circulation circuit. Such a pipe effectively extends the bell nipple and, when connected to the bell nipple, is encompassed herein by the term “bell nipple.”
The drilling-rig operator can use the information from the bell-nipple drilling-fluid monitor to modify circulation-system or drilling parameters. For example, products may be added to the drilling fluid to change the density or viscosity of the drilling fluid based on the density or viscosity at the bell nipple. Or the circulation rate (flow rate) of the drilling fluid can be decreased (e.g., to decrease pressure) or increased (e.g., to increase removal of cuttings). Or the penetration rate of the drill bit may be decreased to stabilize the borehole. In extreme circumstances, information from the bell-nipple drilling-fluid monitor may be used to rapidly shut down the well to prevent a kick by activating the blowout preventer by conventional means (e.g., application of a hydraulic pressure, application of an electronic signal, application of an acoustic signal). The term “blowout preventer” is used herein to refer to one or more blowout preventers in a stack.
The process-pit drilling-fluid monitor and the suction-pit drilling-fluid monitor each operate as described with reference to the bell-nipple drilling-fluid monitor. Measures of pressure provide estimates of drilling-fluid density in the pits and the height of the drilling-fluid surface above the sensors (i.e., the level of drilling fluid in the pits).
The monitors provide information similar to the bell-nipple drilling-fluid monitor (namely, drilling-fluid density and height). Decreases in the level of the drilling fluid (i.e., a decrease in pit volume) can indicate problems in the circulation system, such as a loss of drilling fluid in the hole. Similarity between drilling-fluid density in the processing pit and drilling-fluid density at the bell nipple, or changes in the difference between drilling-fluid density in the processing pit and drilling-fluid density at the bell nipple, can indicate problems with the shale shaker 124a (e.g., a hole in a shaker screen that is allowing coarse cuttings to fall through into the processing pit). Such a problem can decrease the efficiency of the drilling-fluid-cuttings-removal process and can threaten the efficiency of the drilling operation overall. Information from the suction-pit drilling-fluid monitor is the baseline—it indicates properties of the drilling fluid entering the well. This information can be used to modify the drilling fluid by adding products through the hopper 124e.
The controller 504 collects data from the sensors 506, 508, 510 and displays the information via the user input/output system 502. The user may respond to sensor information by instructing the controller to send signals to the BOP control 512, hopper control 514, or centrifuge control 516. For example, the user may respond to the sensor information by increasing the density of the drilling fluid by addition of product in a hopper. The control unit 504 can instruct the hopper control 514 to dispense an amount of product and engage the hopper to mix the product and drilling fluid. Likewise, the addition of fluids may be controlled by control unit 504 instructing the fluids control 518 to dispense an amount of fluids (e.g., water, oil) into the drilling fluid. Certain operations may be automated. For example, based on sensor information indicative of the amount of drilling fluid in the borehole (e.g., the height of the drilling fluid in the bell nipple or in a pit), the control unit 504 may automatically instruct the BOP control 512 to engage the blowout preventer to seal the borehole annulus from the surface to prevent a kick. In more extreme circumstances, the BOP control 512 may be engaged to completely seal the borehole from the surface (e.g., through activation of the shear rams).
Connections among the various components of the exemplary drilling-fluid monitoring system may be by any of a variety of conventional means, such as wires, wireless, and hydraulics. For example, a user interface 502 to the controller 504 may be provided on a smartphone, tablet, or laptop connected to the controller 504 through a wired or wireless network. Similarly, the sensors 506, 508, 510 may be connected to the controller 504 through wireless protocols such as BLUETOOTH or WIFI.
The bell-nipple drilling-fluid monitor may be used alone or in concert with drilling-fluid-pit monitors to provide real-time information of circulating conditions. This information can be used to better—and more safely—perform the drilling operation.
While the foregoing description is directed to the preferred embodiments of the invention, other and further embodiments of the invention will be apparent to those skilled in the art and may be made without departing from the basic scope of the invention. And features described with reference to one embodiment may be combined with other embodiments, even if not explicitly stated above, without departing from the scope of the invention. The scope of the invention is defined by the claims which follow.
| Number | Date | Country | |
|---|---|---|---|
| 62682146 | Jun 2018 | US |
