Treatment method for drilling return loss of offshore carbonate buried hill reservoir

Abstract

The invention belongs to the technical field of petroleum drilling, and discloses an offshore carbonate rock buried hill reservoir drilling return loss processing method, which comprises the following steps of: 1, obtaining hole and crack morphological characteristics and spatial distribution of a carbonate rock buried hill reservoir, and establishing a fracture-cavity reservoir geologic model; secondly, formation pressure distribution of the carbonate rock buried hill reservoir is obtained, and a formation pressure model of the fracture-cavity reservoir is established; and 3, correcting the formation pressure model of the fracture-cavity reservoir by using the formation balance pressure. And 4, obtaining a formation pressure coefficient according to the corrected formation pressure model, and comparing the formation pressure coefficient with the drilling fluid density to obtain a well leakage forecast. And 5, when the drilling encounters return loss, the sea water is pumped into the shaft, the height of the liquid level in the shaft is kept to be 3-5% higher than the height of the original liquid level, and continuous drilling is conducted. According to the method, the well control risk can be accurately predicted in advance, the return-loss leakage can be found and processed in time, and the safe operation of the drilling process is ensured.

Description

Technical Field

[0001] The present invention belongs to the technical field of petroleum drilling, and more particularly, to a method for treating lost circulation during drilling in an offshore carbonate buried hill reservoir. Background Art

[0002] Blowouts, kicks, and leakage are collectively referred to as well control risks in drilling projects. These phenomena all involve pressure imbalances within the wellbore during the drilling process, which may lead to uncontrolled formation fluids, equipment damage, environmental pollution, and even casualties. They are core safety threats in the field of oil and gas extraction.

[0003] Carbonate reservoirs generally refer to all oil and gas reservoirs based on carbonate rocks. Carbonate buried-hill reservoirs specifically refer to carbonate reservoirs located in ancient buried hills beneath regional unconformities. Formed in areas of tectonic uplift, they underwent surface exposure, weathering and erosion, and karstification. Later, they were covered and buried by new strata, retaining ancient weathering crusts. Karst pores and fractures are the primary reservoir spaces.

[0004] Carbonate buried hill reservoirs are prone to loss of return. Carbonate buried hill reservoirs have undergone long-term weathering, erosion, and karstification, forming large caves, fault cavities, and a network of fracture systems. The scale of the leakage channels far exceeds that of conventional porous formations, making it easy to form a loss of return. The reservoir space is extremely unevenly distributed, and sudden losses induced by high pressure differentials exist in some areas: when drilling into unfilled caves or fault zones, drilling fluid instantly flows into large cavities, and the leakage rate far exceeds the pump discharge rate; the fracture network suddenly opens under wellbore pressure fluctuations, resulting in a sudden increase in leakage. Loss of return is usually manifested as the wellhead return volume returning to zero, the circulating tank liquid level continues to drop, and there is no drilling fluid return at the wellhead; the pump pressure suddenly drops during normal drilling; the leakage rate far exceeds the pump discharge rate or direct loss of return.

[0005] To address lost circulation due to loss of return, the following steps are typically followed: First, stop drilling and pull out to a safe section. The bare drill pipe is lowered to the top or bottom of the leaking zone. A graded plugging slurry is then pumped in, maintaining the liquid column pressure through annular grouting. The blowout preventer is then closed and pressurized to force the plugging slurry into the leaking zone. If the leaking zone is a large karst cave, stones or cement balls may be placed first, followed by the injection of quick-setting cement slurry to seal it.

[0006] However, existing methods for addressing lost circulation have significant drawbacks: First, conventional plugging materials are easily diluted and dispersed by high-velocity formation fluids, making it difficult to effectively accumulate and form a plugging layer within the leakage channel. Second, the high-pressure injection process can induce wellbore instability or crack expansion, exacerbating the risk of loss. Third, for deep or complex fracture-cavity systems, the success rate of plugging is low, and recurring leakage is common, resulting in long treatment cycles and high costs.

[0007] In view of this, it is necessary to improve the method for dealing with lost return leakage and provide a method for dealing with lost return leakage in offshore carbonate buried hill reservoir drilling. Summary of the Invention

[0008] In order to at least solve one or more of the technical problems mentioned above, the present invention provides a method for processing lost return leakage in drilling of offshore carbonate buried-hill reservoirs, comprising: a first step of obtaining the morphological characteristics and spatial distribution of pores and fractures in the carbonate buried-hill reservoir based on seismic data, and establishing a geological model of the fracture-cavity reservoir; a second step of obtaining the formation pressure distribution of the carbonate buried-hill reservoir based on the seismic data, and establishing a formation pressure model of the fracture-cavity reservoir; a third step of monitoring the liquid level of the drilling fluid in the wellbore in real time during drilling, calculating the formation equilibrium pressure at the drill bit position, and correcting the formation pressure model of the fracture-cavity reservoir using the formation equilibrium pressure; a fourth step of correcting the formation pressure model based on the correction. The corrected formation pressure model is used to obtain the formation pressure coefficient, which is compared with the drilling fluid density to obtain a lost circulation prediction: if the drilling fluid density is greater than the formation pressure coefficient, it is determined that lost circulation may occur, and the distribution range and loss amount of the lost circulation formation are calculated; the fifth step is to compare the formation pressure of the formation pressure model with the actual formation pressure at the drill bit position when drilling into lost circulation. When the two are consistent, the formation pressure coefficient is obtained based on the formation pressure model; when the two are inconsistent, the formation pressure coefficient is obtained based on the corrected formation pressure model. When the formation pressure coefficient is less than 1.0, seawater is pumped into the wellbore to maintain the liquid level in the wellbore 3-5% higher than the original liquid level, and drilling continues.

[0009] According to one embodiment of the present invention, the scale of the fracture-vuggy reservoir geological model corresponds to that of the formation pressure model.

[0010] According to one embodiment of the present invention, in the second step, the formation pressure distribution of the carbonate buried-hill reservoir is obtained by the following method: obtaining the seismic velocity spectrum and calculating the single-point pressure; combining, interpolating and extrapolating the multi-point pressure values ​​to form a three-dimensional formation pressure distribution model.

[0011] According to one embodiment of the present invention, the following data are read from the seismic velocity spectrum: interval velocity, gradient of root mean square velocity and regional average velocity.

[0012] According to one embodiment of the present invention, the liquid level of the drilling fluid is acquired using a wellhead radar on an offshore platform.

[0013] According to one embodiment of the present invention, the formation equilibrium pressure is calculated based on the height of the drilling fluid exceeding a preset stability plane.

[0014] According to one embodiment of the present invention, the fourth step further includes: if the drilling fluid density is less than the formation pressure coefficient, it is determined that a kick may occur, the kick amount is calculated, and the possibility of a blowout is determined.

[0015] According to one embodiment of the present invention, the fifth step also includes calculating the volume of the fracture-vuggy reservoir near the wellbore based on the fracture-vuggy reservoir geological model, comparing the volume of rock cuttings generated by drilling, and estimating the seawater pumping rate based on the ratio of the volume of the fracture-vuggy reservoir to the volume of rock cuttings generated by drilling.

[0016] According to one embodiment of the present invention, in the fifth step, the liquid level is linked to the seawater pumping rate to control the pump displacement.

[0017] According to one embodiment of the present invention, the fifth step further includes: monitoring the position of the drilling bit corresponding to the geological model of the fractured-cavity reservoir, and improving the sensitivity of monitoring the liquid level of the drilling fluid in the wellbore when drilling holes and cracks.

[0018] The beneficial effects of the present invention are as follows: First, through the integrated seismic geological engineering technology, the carbonate buried hill reservoir is modeled with fracture-cavity reservoirs, and the geological characteristics such as fractures and caves in the reservoir and their spatial distribution scale are identified, which can accurately predict well control risks in advance, including well leakage, well kick and blowout.

[0019] Second, the formation pressure model is corrected in real time, and seismic velocity is used to predict reservoir formation pressure in real time, thereby improving the accuracy of predicting well control risks.

[0020] Third, real-time monitoring of drilling parameters can promptly detect and address lost circulation problems, especially proposing effective treatment measures for large fracture and hole losses, ensuring the safety of the drilling process.

[0021] Fourthly, after a leak occurs, seawater is used to replace the drilling fluid and the liquid level is controlled, which not only avoids the frequent use of high-cost plugging agents and reduces plugging costs, but also maintains the wellbore pressure balance and prevents well wall collapse, ultimately ensuring safe and efficient drilling. BRIEF DESCRIPTION OF THE DRAWINGS

[0022] The above and other objects, features and advantages of the exemplary embodiments of the present invention will become readily understood by reading the following detailed description with reference to the accompanying drawings. In the accompanying drawings, several embodiments of the present invention are shown in an illustrative and non-limiting manner, and the same or corresponding reference numerals represent the same or corresponding parts, wherein:

[0023] Figure 1 A schematic diagram showing the steps of a method for treating lost circulation during drilling in offshore carbonate buried hill reservoirs is provided;

[0024] Figure 2 A schematic diagram of a three-dimensional seismic exploration system is shown. DETAILED DESCRIPTION

[0025] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of them. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative work shall fall within the scope of protection of the present invention.

[0026] It should be understood that the terms "include" and "comprising" used in the description and claims of the present invention indicate the presence of described features, integers, steps, operations, elements and / or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components and / or collections thereof.

[0027] It should also be understood that the terminology used in this specification is for the purpose of describing specific embodiments only and is not intended to limit the present invention. As used in the specification and claims, the singular forms "a," "an," and "the" are intended to include the plural forms unless the context clearly indicates otherwise. It should further be understood that the term "and / or" as used in the specification and claims refers to any and all possible combinations of one or more of the associated listed items, including and including these combinations.

[0028] As used in this specification and claims, the term "if" can be interpreted as "when" or "upon" or "in response to determining" or "in response to detecting," depending on the context. Similarly, the phrase "if it is determined" or "if [described condition or event] is detected" can be interpreted as meaning "upon determination" or "in response to determining" or "upon detection of [described condition or event]" or "in response to detecting [described condition or event]," depending on the context.

[0029] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings.

[0030] Figure 1 A schematic diagram showing the steps of a method for treating lost circulation during drilling in offshore carbonate buried-hill reservoirs is provided.

[0031] like Figure 1As shown, a method for processing lost circulation during drilling in an offshore carbonate buried-hill reservoir comprises: a first step S1, obtaining the morphological characteristics and spatial distribution of pores and fractures in the carbonate buried-hill reservoir based on seismic data, and establishing a geological model of the fracture-cavity reservoir; a second step S2, obtaining the formation pressure distribution of the carbonate buried-hill reservoir based on the seismic data, and establishing a formation pressure model of the fracture-cavity reservoir; a third step S3, monitoring the liquid level of the drilling fluid in the wellbore in real time during drilling, calculating the formation equilibrium pressure at the drill bit position, and correcting the formation pressure model of the fracture-cavity reservoir using the formation equilibrium pressure; a fourth step S4, obtaining the formation pressure distribution according to the corrected formation pressure model The formation pressure coefficient is compared with the drilling fluid density to obtain a lost circulation prediction: if the drilling fluid density is greater than the formation pressure coefficient, it is determined that lost circulation may occur, and the distribution range and loss amount of the lost circulation formation are calculated; in the fifth step S5, when lost circulation is encountered during drilling, the formation pressure of the formation pressure model is compared with the actual formation pressure at the drill bit position. When the two are consistent, the formation pressure coefficient is obtained based on the formation pressure model. When the two are inconsistent, the formation pressure coefficient is obtained based on the corrected formation pressure model. When the formation pressure coefficient of the formation is less than 1.0, seawater is pumped into the wellbore to maintain the liquid level in the wellbore 3-5% higher than the original liquid level, and drilling continues.

[0032] In the first step, the fracture-vuggy reservoir geological model refers to a three-dimensional geological model constructed by integrating the morphology and spatial distribution of pores and fractures, in which parameters such as porosity and permeability are quantified to provide basic data for reservoir exploration.

[0033] Using 3D seismic data, mathematical algorithms extract physical quantities reflecting subsurface lithologic and structural differences to identify reservoirs. For example, structural tensors quantify stratigraphic discontinuities and identify fracture boundaries; coherent energy gradients highlight the beaded reflection characteristics of dissolution pores and vugs; and variance attributes characterize the chaotic reflection patterns of fracture zones. Pore and fracture characteristics are then used to differentiate and identify reservoirs, thereby determining the morphological and spatial distribution characteristics of pores and fractures in carbonate buried-hill reservoirs.

[0034] In the present invention, the constructed fracture-vuggy reservoir geological model is limited to the drilling area and is used to guide the prediction of well control risks during the drilling process and to deal with loss of return situations.

[0035] In the second step, the formation pressure distribution of the carbonate buried-hill reservoir is obtained through seismic data. In essence, the pressure value of each point is calculated through the velocity spectrum, and then a pressure model is constructed.

[0036] Under normal compaction, formation velocity increases regularly with depth. However, under abnormally high pressure, the formation may appear undercompacted, characterized by increased porosity and decreased density, resulting in seismic wave propagation velocities significantly lower than those in normally compacted layers at the same depth. Preferably, the formation pressure distribution of a carbonate buried-hill reservoir is obtained by: obtaining a seismic velocity spectrum and calculating single-point pressure; and combining, interpolating, and extrapolating multiple-point pressure values ​​to form a three-dimensional formation pressure distribution model. More preferably, the following data is read from the seismic velocity spectrum: interval velocity, root mean square velocity gradient, and regional average velocity.

[0037] Specifically, first, the layer velocity data is extracted from the seismic velocity spectrum data, and the pressure is calculated using the Fillippone method or the improved Fillippone method. This method uses the ratio of the layer velocity to the velocity when the porosity approaches zero and the velocity when the rigidity approaches zero as a link, combined with the empirical formula of the overburden pressure, such as P ov =0.465×ρ×H, where ρ is the average density and H is the burial depth, which converts the velocity anomaly into formation pressure value.

[0038] Carbonate buried-hill reservoirs are highly heterogeneous due to the development of fractures and caves. Their pressure distribution is controlled by the sealing and connectivity of the fracture-cavity system. For example, zones with dense fractures are prone to localized pressure storage, while fluid enrichment at the edges of large caves can lead to sudden pressure changes. Boundary displacement inversion theory can be applied to infer the distribution of the in-situ stress field from seismic data. Pore pressure can be calculated using a modified Biot coefficient (α≈0.9 for dolomite and α≈0.7 for limestone). This coefficient characterizes the influence of pore pressure on the rock structure and can correct for errors in traditional clastic rock compaction theory for carbonate rocks.

[0039] Preferably, the fracture-vuggy reservoir geological model and the formation pressure model have corresponding scales, and the two form a digital twin model that corresponds to each other.

[0040] In the third step, the change in the liquid level of the drilling fluid in the wellbore reflects the change in the equilibrium pressure of the formation.

[0041] During drilling, the drilling fluid circulation system must ensure a balance between return and injection volumes. The fluid level typically remains relatively stable within the circulation tank. An abnormally high fluid level may indicate formation fluid intrusion into the wellbore, leading to overflow. Conversely, an abnormally low fluid level may indicate lost circulation.

[0042] In the present invention, the height of the drilling fluid's stability plane is predetermined based on the pressure coefficient derived from the formation pressure model. By monitoring the drilling fluid level in the wellbore in real time, the height difference between it and the stability plane can be calculated, thereby determining the pressure generated by this difference. When this pressure is positive, the overall pressure in the formation pressure model needs to be adjusted to increase; when it is negative, the overall pressure in the formation pressure model needs to be adjusted to decrease. This ensures that the corrected formation pressure model closely matches the actual formation pressure distribution.

[0043] Preferably, the liquid level of the drilling fluid is acquired by using a wellhead radar on an offshore platform. The formation equilibrium pressure is calculated based on the height of the drilling fluid exceeding a preset stable plane.

[0044] In the fourth step, the formation pressure coefficient refers to the ratio of the pressure read from the formation pressure model to the net water pressure at that depth. The drilling fluid density is set according to the initial formation pressure model. When the drill bit reaches a certain location, the well control risk can be predicted by comparing the drilling fluid density with the formation pressure coefficient read from the last calibrated formation pressure model. Specifically, if the drilling fluid density is greater than the formation pressure coefficient, it is determined that lost circulation is likely. The distribution and volume of lost circulation in the lost circulation formation are calculated to provide data support for risk control.

[0045] The distribution range and leakage volume of the lost-return formation can be determined based on the corresponding pore and fracture morphologies in the fracture-cavity reservoir geological model obtained in the first step.

[0046] Furthermore, if the drilling fluid density is less than the formation pressure coefficient, a kick is considered likely, and the kick volume is calculated to determine the likelihood of a blowout. The kick volume can be determined based on the difference between the two and wellbore data.

[0047] In the fifth step, the actual formation pressure refers to the pressure calculated based on the wellbore fluid column. A clear sign of a lost return is a downward trend in the drilling fluid volume. Based on the fracture reservoir geological model and formation pressure model established above, the accurate formation pressure coefficient is first obtained: determine whether the formation pressure model needs to be corrected. If so, the formation pressure coefficient is obtained after the correction; if not, the formation pressure coefficient is obtained before the correction. Then determine whether the formation pressure coefficient is less than 1.0. When the above conditions are met, it means that seawater can be injected. The reason is that the density of seawater is approximately 1.03 times that of pure water, and it can be temporarily used as drilling fluid.

[0048] In the present invention, when a loss of return occurs during drilling, seawater is injected into the wellbore as drilling fluid, and the liquid level in the wellbore is maintained at 3-5% higher than the original liquid level. This allows the seawater injection volume and speed to be approximately equal to the loss volume and speed, maintaining a balanced liquid level. This not only seals the hydrogen sulfide gas to prevent it from overflowing, but also ensures drilling progress and drilling safety.

[0049] Preferably, the volume of the fracture-vuggy reservoir near the wellbore is calculated based on the geological model of the fracture-vuggy reservoir, and the volume of the rock cuttings generated by drilling is compared. Based on the ratio of the volume of the fracture-vuggy reservoir to the volume of the rock cuttings generated by drilling, the seawater pumping rate is estimated. The pump power can be set accordingly, providing data support for preparations for dealing with loss of return.

[0050] Preferably, the liquid level is associated with the seawater pumping rate and the pump displacement is controlled, so that the liquid level can be controlled in real time.

[0051] Preferably, the drill bit is monitored at a location corresponding to a fracture-vuggy reservoir geological model, increasing the sensitivity of the drilling fluid level monitoring system within the wellbore when encountering holes or cracks. By pre-measuring the drilling trajectory and noting it in the fracture-vuggy reservoir geological model, it is possible to predict the hole, crack, or other reservoir type corresponding to the drill bit at each moment during the drilling process. At this location, the probability of leakage is significantly increased. In the present invention, by increasing the sensitivity of the fluid level monitoring system when the drill bit passes through these locations, leakage can be detected in a targeted manner.

[0052] Figure 2 A schematic diagram of a three-dimensional seismic exploration system is shown.

[0053] like Figure 2As shown, in the system 100, multiple spaced-apart geophones 110 for detecting seismic waves are arranged on the surface 101 of the target exploration area, forming a geophone array covering the target area on a plane. These geophones 110 are connected to a seismic information processing device via wired or wireless connections. Multiple seismic sources 120 are also provided. The seismic information processing device can perform preliminary processing on the seismic data. The operating process of the 3D seismic exploration system is as follows: seismic sources 120 located at multiple locations are artificially excited to generate seismic waves. These seismic waves are reflected from the boundaries of the stratum 102 and received by the geophone array, forming seismic information collected on a plane that varies with time. The seismic information received by the geophone array represents certain measures of seismic wave energy as a function of time, such as displacement, velocity, wave impedance, and pressure. This information can be grouped in various ways, such as traces or sets, and then processed or format-converted according to the correspondence between time and space to form a 3D seismic data volume in the form of a 3D array, thereby obtaining high-quality 3D seismic fine imaging data. This 3D seismic data volume is formed by spatially stacking interface points. The interpretation of three-dimensional seismic data can observe the morphology of geological interfaces from different directions and study the changes of geological bodies in three-dimensional space by cutting cross sections, longitudinal sections and horizontal slices.

[0054] In the present invention, seismic data comes from Figure 2 The three-dimensional seismic exploration system shown.

[0055] In the present invention, by constructing a fracture-cavity reservoir geological model and a formation pressure model, data support is provided for the prediction of well control risks in offshore carbonate buried-hill reservoir drilling, which can achieve advanced warning of leakage risks. The formation pressure model is corrected by real-time monitoring of the drilling fluid liquid level, so that the obtained corrected formation pressure model is closer to the actual formation, significantly improving the prediction accuracy of well control risks. After a leakage occurs, the drilling fluid is replaced with seawater and the liquid level is controlled, which not only avoids the frequent use of high-cost plugging agents and reduces the cost of plugging, but also maintains the wellbore pressure balance, prevents the well wall from collapsing, and ultimately ensures safe and efficient drilling.

[0056] Although a number of embodiments of the present invention have been shown and described herein, it will be apparent to those skilled in the art that such embodiments are provided by way of example only. Those skilled in the art may devise numerous modifications, variations, and alternatives without departing from the concept and spirit of the present invention. It should be understood that in practicing the present invention, various alternatives to the embodiments of the present invention described herein may be employed. The appended claims are intended to define the scope of the present invention and therefore cover equivalents or alternatives within the scope of these claims.

Claims

1. A method for treating lost circulation during drilling in an offshore carbonate buried hill reservoir, characterized in that: include: The first step is to obtain the morphological characteristics and spatial distribution of pores and fractures in the carbonate buried hill reservoir based on seismic data and establish a fracture-cavity reservoir geological model; The second step is to obtain the formation pressure distribution of the carbonate buried hill reservoir based on seismic data and establish a formation pressure model for the fracture-cavity reservoir; The third step is to monitor the liquid level of the drilling fluid in the wellbore in real time during the drilling process, calculate the formation equilibrium pressure at the drill bit position, and use the formation equilibrium pressure to correct the formation pressure model of the fracture-cavity reservoir; The fourth step is to obtain the formation pressure coefficient based on the calibrated formation pressure model and compare it with the drilling fluid density to obtain a lost circulation prediction. If the drilling fluid density is greater than the formation pressure coefficient, it is determined that lost circulation may occur, and the distribution range and loss volume of the lost circulation formation are calculated. The fifth step is to compare the formation pressure of the formation pressure model with the actual formation pressure at the drill bit position when a loss of return occurs during drilling. When the two are consistent, the formation pressure coefficient is obtained based on the formation pressure model. When the two are inconsistent, the formation pressure coefficient is obtained based on the corrected formation pressure model. When the formation pressure coefficient is less than 1.0, seawater is pumped into the wellbore to maintain the liquid level in the wellbore higher than the original liquid level by 3 to 5%, and drilling continues.

2. The processing method according to claim 1, characterized in that The fracture-vuggy reservoir geological model corresponds to the scale of the formation pressure model.

3. The processing method according to claim 1, characterized in that In the second step, the formation pressure distribution of the carbonate buried hill reservoir is obtained by the following method: Obtain seismic velocity spectrum and calculate single point pressure; Multi-point pressure values ​​are combined, interpolated, and extrapolated to form a three-dimensional formation pressure distribution model.

4. The processing method according to claim 3, characterized in that The following data are read from the seismic velocity spectrum: interval velocity, gradient of root mean square velocity and regional average velocity.

5. The processing method according to claim 1, characterized in that The liquid level of the drilling fluid is obtained by using a wellhead radar on an offshore platform.

6. The processing method according to claim 1, characterized in that The formation equilibrium pressure is calculated based on the height of the drilling fluid exceeding a preset stability plane.

7. The processing method according to claim 1, characterized in that The fourth step further includes: if the drilling fluid density is less than the formation pressure coefficient, determining that a kick may occur, calculating the kick volume and determining the possibility of a blowout.

8. The processing method according to claim 1, characterized in that The fifth step also includes calculating the volume of the fracture-vuggy reservoir near the wellbore based on the fracture-vuggy reservoir geological model, comparing the volume of rock cuttings generated by drilling, and estimating the seawater pumping rate based on the ratio of the volume of the fracture-vuggy reservoir to the volume of rock cuttings generated by drilling.

9. The processing method according to claim 1, characterized in that: In the fifth step, the liquid level is related to the seawater pumping rate to control the pump displacement.

10. The processing method according to claim 1, characterized in that: The fifth step also includes: monitoring the position of the drilling bit corresponding to the geological model of the fracture-cavity reservoir, and improving the sensitivity of monitoring the liquid level of the drilling fluid in the wellbore when drilling holes and cracks.

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