DYNAMIC ANNULAR PRESSURE CONTROL APPARATUS AND METHOD

Description

Field of the Invention

[0001] The present method and apparatus are related to a method for dynamic well borehole annular pressure control, more specifically, a selectively closed-loop, pressurized method for controlling borehole pressure during drilling and other well completion operations.

Background of the Art

[0002] The exploration and production of hydrocarbons from subsurface formations ultimately requires a method to reach and extract the hydrocarbons from the formation. This is typically done with a drilling rig. In its simplest form, this constitutes a land-based drilling rig that is used to support a drill bit mounted on the end of drill string, comprised of a series of drill tubulars. A fluid comprised of a base fluid, typically water or oil, and various additives are pumped down the drill string, and exits through the rotating drill bit. The fluid then circulates back up the annulus formed between the borehole wall and the drill bit, taking with it the cuttings from the drill bit and clearing the borehole. The fluid is also selected such that the hydrostatic pressure applied by the fluid is greater than surrounding formation pressure, thereby preventing formation fluids from entering into the borehole. It also causes the fluid to enter into the formation pores, or "invade" the formation. Further, some of the additives from the pressurized fluid adhere to the formation walls forming a "mud cake" on the formation walls. This mud cake helps to preserve and protect the formation prior to the setting of casing in the drilling process, as will be discussed further below. The selection of fluid pressure in excess of formation pressure is commonly referred to as over balanced drilling. The fluid then returns to the surface, where it is bled off into a mud system, generally comprised of a shaker table, to remove solids, a mud pit and a manual or automatic means for addition of various chemicals or additives to the returned fluid. The clean, returned fluid flow is measured to determine fluid losses to the formation as a result of fluid invasion. The returned solids and fluid (prior to treatment) may be studied to determine various formation characteristics used in drilling operations. Once the fluid has been treated in the mud pit, it is then pumped out of the mud pit and re-injected into the top of the drill string again.

[0003] This overbalanced technique is the most commonly used fluid pressure control method. It relies primarily on the fluid density and hydrostatic force generated by the column of fluid in the annulus to generate pressure. By exceeding the formation pore pressure, the fluid is used to prevent sudden releases of formation fluid to the borehole, such as gas kicks. Where such gas kicks occur, the density of the fluid may be increased to prevent further formation fluid release to the borehole. However, the addition of weighting additives to increase fluid density (a) may not be rapid enough to deal with the formation fluid release and (b) may exceed the formation fracture pressure, resulting in the creation of fissures or fractures in the formation, with resultant fluid loss to the formation, possibly adversely affecting near borehole permeability. In such events, the operator may elect to close the blow out preventors (BOP) below the drilling rig floor to control the movement of the gas up the annulus. The gas is bled off and the fluid density is increased prior to resuming drilling operations.

[0004] The use of overbalanced drilling also affects the selection of casing during drilling operations. The drilling process starts with a conductor pipe being driven into the ground, a BOP stack attached to the drilling conductor, with the drill rig positioned above the BOP stack. A drill string with a drill bit may be selectively rotated by rotating the entire string using the rig kelly or a top drive, or may be rotated independent of the drill string utilizing drilling fluid powered mechanical motors installed in the drill string above the drill bit. As noted above, an operator may drill open hole for a period until such time as the accumulated fluid pressure at a calculated depth nears that of the formation fracture pressure. At that time, it is common practice to insert and hang a casing string in the borehole from the surface down to the calculated depth. A cementing shoe is placed on the drill string and specialized cement is injected into the drill string, to travel up the annulus and displace any fluid then in the annulus. The cement between the formation wall and the outside of the casing effectively supports and isolates the formation from the well bore annulus and further open hole drilling is carried out below the casing string, with the fluid again providing pressure control and formation protection.

[0005] Fig. 1 is an exemplary diagram of the use of fluids during the drilling process in an intermediate borehole section. The top horizontal bar represents the hydrostatic pressure exerted by the drilling fluid and the vertical bar represents the total vertical depth of the borehole. The formation pore pressure graph is represented by line 10. As noted above, in an over balanced situation, the fluid pressure exceeds the formation pore pressure for reasons of pressure control and hole stability. Line 12 represents the formation fracture pressure. Pressures in excess of the formation fracture pressure will result in the fluid pressurizing the formation walls to the extent that small cracks or fractures will open in the borehole wall and the fluid pressure overcomes the formation pressure with significant fluid invasion. Fluid invasion can result in reduced permeability, adversely affecting formation production. The annular pressure generated by the fluid and its additives is represented by line 14 and is a linear function of the total vertical depth. The pure hydrostatic pressure that would be generated by the fluid, less additives, i.e., water, is represented by line 16.

[0006] In an open loop fluid system described above, the annular pressure seen in the borehole is a linear function of the borehole fluid. This is true only where the fluid is at a static density. While the fluid density may be modified during drilling operations, the resulting pressure annular pressure is generally linear. In Fig. 1, the hydrostatic pressure 16 and the pore pressure 10 generally track each other in the intermediate section to a depth of approximately 7000 feet. Thereafter, the pore pressure 10 increases in the interval from a depth of 7000 feet to approximately 9300 feet. This may occur where the borehole penetrates a formation interval having significantly different characteristics than the prior formation. The annular pressure 14 maintained by the fluid 14 is safely above the pore pressure prior to 7000 feet. In the 7000 - 9300 foot interval, the differential between the pore pressure 10 and annular pressure 14 is significantly reduced, decreasing the margin of safety during operations. A gas kick in this interval may result in the pore pressure exceeding the annular pressure with a release of fluid and gas into the borehole, possibly requiring activation of the surface BOP stack. As noted above, while additional weighting material may be added to the fluid, it will be generally ineffective in dealing with a gas kick due to the time required to increase the fluid density as seen in the borehole.

[0007] Fluid circulation itself also creates problems in an open system. It will be appreciated that it is necessary to shut off the mud pumps in order to make up successive drill pipe joints. When the pumps are shut off, the annular pressure will undergo a negative spike that dissipates as the annular pressure stabilizes. Similarly, when the pumps are turned back on, the annular pressure will undergo a positive spike. This occurs each time a pipe joint is added to or removed from the string. It will be appreciated that these spikes can cause fatigue on the borehole cake and could result in formation fluids entering the borehole, again leading to a well control event.

[0008] In contrast to open fluid circulation systems, there have been developed a number of closed fluid handling systems. Examples of these include US patents 5,857,522 and 6,035,952, both to Bradfield et al. and assigned to Baker Hughes Incorporated. In these patents, a closed system is used for the purposes of underbalanced drilling, i.e., the annular pressure is less than that of the formation pore pressure. Underbalanced drilling is generally used where the formation is a chalk or other fractured limestone and the desire is to prevent mud cake from plugging fractures in the formation. Moreover, it will be appreciated that where underbalanced systems are used, a significant well event will require that the BOPs be closed to handle the kick or other sudden pressure increase.

[0009] Other systems have been designed to maintain fluid circulation during the addition or removal of additional drill string tubulars (make/break). In US patent 6,352,129, assigned to Shell Oil Company, assignee of the present invention, a continuous circulation system is shown whereby the make up/break operations and the separate pipe sections are isolated from each other in a fluid chamber 20 and a secondary conduit 28 is used to supply pumped fluid to that portion of the drill string 12 still in fluid communications with the formation. In a second implementation, the publication discloses an apparatus and method for injecting a fluid or gas into the fluid stream after the pumps have been turned off to maintain and control annular pressure.

[0010] WO-A-0250398 discloses a system for drilling of wells whereby drilling fluid is pumped down a drill string and up an annular space formed between the drill string and the wellbore wall, the annular space being closed at its upper end by a pressure containment device. The drilling fluid is discharged from the annular space via a pipe provided with a flow/pressure control device controlled by a central data acquisition and control system that is programmed to detect a real time discrepancy between predicted and monitored flow-out and to control the flow/pressure control device to maintain a desired backpressure in the well.

[0011] WO-A-0079092 discloses a system for controlling formation pressure during the drilling of a subterranean formation, comprising a drill string extending into a borehole, the drill string including a bottom hole assembly comprising a drill bit, a primary pump for selectively pumping a drilling fluid from a drilling fluid source, through said drill string, out said drill bit and into an annular space created as said drill string penetrates the formation, a fluid discharge conduit in fluid communication with said annular space for discharging said drilling fluid to a reservoir to clean said drilling fluid for reuse, and a fluid backpressure system connected to said fluid discharge conduit; said fluid backpressure system comprised of a fluid choke, a backpressure pump, and a fluid source, whereby said backpressure pump may be selectively activated to increase annular space drilling fluid pressure.

Summary of the Present Invention

[0012] The present invention is directed to a closed loop, overbalanced drilling system having a variable overbalance pressure capability. The present invention further utilizes information related to the wellbore, drill rig and drilling fluid as inputs to a model to predict downhole pressure. The predicted downhole pressure is then compared to a desired downhole pressure and the differential is utilized to control a backpressure system. The present invention further utilizes actual downhole pressure to calibrate the model and modify input parameters to more closely correlate predicted downhole pressures to measured downhole pressures. The system according to the invention is defined by claim 1.

[0013] In one aspect, the present invention is capable of modifying annular pressure during circulation by the addition of backpressure, thereby increasing the annular pressure without the addition of weighting additives to the fluid. It will be appreciated that the use of backpressure to increase annular pressure is more responsive to sudden changes in formation pore pressure.

[0014] In yet another aspect, the present invention is capable of maintaining constant annular pressure during primary pump shut down when drill pipe is being added to or removed from the string. By maintaining pressure in the annulus, the mud cake build up on the formation wall is maintained and does not see sudden spikes or drops in annular pressure.

[0015] In yet another aspect, the present invention utilizes an accurate mass-balance flow meter that permits accurate determination of fluid gains or losses in the system, permitting the operator to better manage the fluids involve in the operation.

[0016] In yet another aspect, the present invention includes automated sensors to determine annular pressure, flow, and with depth information, can be used to predict pore pressure, allowing the present invention to increase annular pressure in advance of drilling through the section in question.

Brief Description of the Drawings

[0017] A better understanding of the present invention may be had by referencing the following drawings in conjunction with the Detailed Description of the Preferred Embodiment, in which

Figure 1 is a graph depicting annular pressures and formation pore and fracture pressures;

Figures 2 is a plan view depicting a surface drilling system employing the current invention;

Figure 3 is a block diagram of the pressure monitoring and control system utilized in the preferred embodiment;

Figure 4 is a functional diagram of the operation of the pressure monitoring and control system;

Figure 5 is a graph depicting the correlation of predicted annular pressures to measured annular pressures;

Figure 6 is a graph depicting the correlation of predicted annular pressures to measured annular pressures depicted in Figure 5, upon modification of certain model parameters;

Figure 7 is a graph depicting how the method of the present invention may be used to control variations in formation pore pressure in an overbalanced condition;

Figure 8 is a graph depicting the method of the present invention as applied to at balanced drilling; and

Figures 9A and 9B are graphs depicting how the present invention may be used to counteract annular pressure drops and spikes that accompany pump off/pump on conditions.

Detailed Description of the Preferred Embodiment

[0018] The present invention is intended to achieve Dynamic Annulus Pressure Control (DAPC) of a well bore during drilling and intervention operations.

Structure of the Preferred Embodiment

[0019] Figure 2 is a plan view depicting a surface drilling system employing the current invention. It will be appreciated that an offshore drilling system may likewise employ the current invention. The drilling system 100 is shown as being comprised of a drilling rig 102 that is used to support drilling operations. Many of the components used on a rig 102, such as the kelly, power tongs, slips, draw works and other equipment are not shown for ease of depiction. The rig 102 is used to support drilling and exploration operations in formation 104. As depicted in Fig. 2 the borehole 106 has already been partially drilled, casing 108 set and cemented 109 into place. In the preferred embodiment, a casing shutoff mechanism, or downhole deployment valve, 110 is installed in the casing 108 to optionally shutoff the annulus and effectively act as a valve to shut off the open hole section when the bit is located above the valve.

[0020] The drill string 112 supports a bottom hole assembly (BHA) 113 that includes a drill bit 120, a mud motor 118, a MWD/LWD sensor suite 119, including a pressure transducer 116 to determine the annular pressure, a check valve, to prevent backflow of fluid from the annulus. It also includes a telemetry package 122 that is used to transmit pressure, MWD/LWD as well as drilling information to be received at the surface While Fig. 2A illustrates a BHA utilizing a mud telemetry system, it will be appreciated that other telemetry systems, such as radio frequency (RF), electromagnetic (EM) or drilling string transmission systems may be employed within the present invention..

[0021] As noted above, the drilling process requires the use of a drilling fluid 150, which is stored in reservoir 136. The reservoir 136 is in fluid communications with one or more mud pumps 138 which pump the drilling fluid 150 through conduit 140. The conduit 140 is connected to the last joint of the drill string 112 that passes through a rotating or spherical BOP 142. A rotating BOP 142, when activated, forces spherical shaped elastomeric elements to rotate upwardly, closing around the drill string 112, isolating the pressure, but still permitting drill string rotation. Commercially available spherical BOPs, such as those manufactured by Varco International, are capable of isolating annular pressures up to 10,000 psi (68947.6 kPa). The fluid 150 is pumped down through the drill string 112 and the BHA 113 and exits the drill bit 120, where it circulates the cuttings away from the bit 120 and returns them up the open hole annulus 115 and then the annulus formed between the casing 108 and the drill string 112. The fluid 150 returns to the surface and goes through diverter 117, through conduit 124 and various surge tanks and telemetry systems (not shown).

[0022] Thereafter the fluid 150 proceeds to what is generally referred to as the backpressure system 131. The fluid 150 enters the backpressure system 131 and flows through a flow meter 126. The flow meter 126 may be a mass-balance type or other high-resolution flow meter. Utilizing the flow meter 126, an operator will be able to determine how much fluid 150 has been pumped into the well through drill string 112 and the amount of fluid 150 returning from the well. Based on differences in the amount of fluid 150 pumped versus fluid 150 returned, the operator is be able to determine whether fluid 150 is being lost to the formation 104, which may indicate that formation fracturing has occurred, i.e., a significant negative fluid differential. Likewise, a significant positive differential would be indicative of formation fluid entering into the well bore.

[0023] The fluid 150 proceeds to a wear resistant choke 130. It will be appreciated that there exist chokes designed to operate in an environment where the drilling fluid 150 contains substantial drill cuttings and other solids. Choke 130 is one such type and is further capable of operating at variable pressures and through multiple duty cycles. The fluid 150 exits the choke 130 and flows through valve 121. The fluid 150 is then processed by an optional degasser 1 and by a series of filters and shaker table 129, designed to remove contaminates, including cuttings, from the fluid 150. The fluid 150 is then returned to reservoir 136. A flow loop 119A, is provided in advance of valve 125 for feeding fluid 150 directly a backpressure pump 128. Alternatively, the backpressure pump 128 may be provided with fluid from the reservoir through conduit 119B, which is fluid communications with the reservoir 1 (trip tank). The trip tank is normally used on a rig to monitor fluid gains and losses during tripping operations. In the this invention, this functionality is maintained. A three-way valve 125 may be used to select loop 119A, conduit 119B or isolate the backpressure system. While backpressure pump 128 is capable of utilizing returned fluid to create a backpressure by selection of flow loop 119A, it will be appreciated that the returned fluid could have contaminates that have not been removed by filter/shaker table 129. As such, the wear on backpressure pump 128 may be increased. As such, the preferred fluid supply to create a backpressure would be to use conduit 119A to provide reconditioned fluid to backpressure pump 128.

[0024] In operation, valve 125 would select either conduit 119A or conduit 119B, and the backpressure pump 128 engaged to ensure sufficient flow passes the choke system to be able to maintain backpressure, even when there is no flow coming from the annulus 115. In the preferred embodiment, the backpressure pump 128 is capable of providing up to approximately 2200 psi (15168.5 kPa) of backpressure; though higher pressure capability pumps may be selected.

[0025] The ability to provide backpressure is a significant improvement over normal fluid control systems. The pressure in the annulus provided by the fluid is a function of its density and the true vertical depth and is generally a by approximation linear function. As noted above, additives added to the fluid in reservoir 136 must be pumped downhole to eventually change the pressure gradient applied by the fluid 150.

[0026] The preferred embodiment of the present invention further includes a flow meter 152 in conduit 100 to measure the amount of fluid being pumped downhole. It will be appreciated that by monitoring flow meters 126, 152 and the volume pumped by the backpressure pump 128, the system is readily able to determine the amount of fluid 150 being lost to the formation, or conversely, the amount of formation fluid leaking to the borehole 106. Further included in the present invention is a system for monitoring well pressure conditions and predicting borehole 106 and annulus 115 pressure characteristics.

DAPC Monitoring System

[0027] Figure 3 is a block diagram of the pressure monitoring system 146 of the preferred embodiment of the present invention. System inputs to the monitoring system 146 include the downhole pressure 202 that has been measured by sensor package119, transmitted by MWD pulser package 122 and received by transducer equipment (not shown) on the surface. Other system inputs include pump pressure 200, input flow 204 from flow meter 152, penetration rate and string rotation rate, as well as weight on bit (WOB) and torque on bit (TOB) that may be transmitted from the BHA 113 up the annulus as a pressure pulse. Return flow is measured using flow meter 126. Signals representative of the data inputs are transmitted to a control unit 230, which is it self comprised of a drill rig control unit 232, a drilling operator's station 234, a DAPC processor 236 and a back pressure programmable logic controller (PLC) 238, all of which are connected by a common data network 240. The DAPC processor 236 serves three functions, monitoring the state of the borehole pressure during drilling operations, predicting borehole response to continued drilling, and issuing commands to the, backpressure PLC to control the variable choke 130 and backpressure pump 128. The specific logic associated with the DAPC processor 236 will be discussed further below.

Calculation of Backpressure

[0028] A schematic model of the functionality of the DAPC pressure monitoring system 146 is set forth in Figure 4. The DAPC processor 236 includes programming to carry out Control functions and Real Time Model Calibration functions. The DAPC processor receives data from various sources and continuously calculates in real time the correct backpressure set-point based on the input parameters. The set-point is then transferred to the programmable logic controller 238, which generates the control signals for backpressure pump 128. The input parameters fall into three main groups. The first are relatively fixed parameters 250, including parameters such as well and casing string geometry, drill bit nozzle diameters, and well trajectory. While it is recognized that the actual well trajectory may vary from the planned trajectory, the variance may be taken into account with a correction to the planned trajectory. Also within this group of parameters are temperature profile of the fluid in the annulus and the fluid composition. As with the trajectory parameters, these are generally known and do not change over the course of the drilling operations. In particular, with the DAPC system, one objective is keeping the fluid 150 density and composition relatively constant, using backpressure to provide the additional pressure to control the annulus pressure.

[0029] The second group of parameters 252 are variable in nature and are sensed and logged in real time. The common data network 240 provides this information to the DAPC processor 236. This information includes flow rate data provided by both downhole and return flow meters 152 and 126, respectively, the drill string rate of penetration (ROP) or velocity, the drill string rotational speed, the bit depth, and the well depth, the latter two being derived from rig sensor data. The last parameter is the downhole pressure data 254 that is provided by the downhole MWD/LWD sensor suite 119 and transmitted back up the annulus by the mud pulse telemetry package 122. One other input parameters is the set-point downhole pressure 256, the desired annulus pressure.

[0030] The functionally the control module 258 attempts to calculate the pressure in the annulus over its fill well bore length utilizing various models designed for various formation and fluid parameters. The pressure in the well bore is a function not only of the pressure or weight of the fluid column in the well, but includes the pressures caused by drilling operations, including fluid displacement by the drill string, frictional losses returning up the annulus, and other factors. In order to calculate the pressure within the well, the control module 258 considers the well as a finite number of segments, each assigned to a segment of well bore length. In each of the segments the dynamic pressure and the fluid weight is calculated and used to determine the pressure differential 262 for the segment. The segments are summed and the pressure differential for the entire well profile is determined.

[0031] It is known that the flow rate of the fluid 150 being pumped downhole is proportional to the flow velocity of fluid 150 and may be used to determine dynamic pressure loss as the fluid is being pumped downhole. The fluid 150 density is calculated in each segment, taking into account the fluid compressibility, estimated cutting loading and the thermal expansion of the fluid for the specified segment, which is itself related to the temperature profile for that segment of the well. The fluid viscosity at the temperature profile for the segment is also instrumental in determining dynamic pressure losses for the segment. The composition of the fluid is also considered in determining compressibility and the thermal expansion coefficient. The drill string ROP is related to the surge and swab pressures encountered during drilling operations as the drill string is moved into or out of the borehole. The drill string rotation is also used to determine dynamic pressures, as it creates a frictional force between the fluid in the annulus and the drill string. The bit depth, well depth, and well/string geometry are all used to help create the borehole segments to be modeled. In order to calculate the weight of the fluid, the preferred embodiment considers not only the hydrostatic pressure exerted by fluid 150 , but also the fluid compression, fluid thermal expansion and the cuttings loading of the fluid seen during operations. It will be appreciated that the cuttings loading can be determined as the fluid is returned to the surface and reconditioned for further use. All of these factors go into calculation of the "static pressure".

[0032] Dynamic pressure considers many of the same factors in determining static pressure. However, it further considers a number of other factors. Among them is the concept of laminar versus turbulent flow. The flow characteristics are a function of the estimated roughness, hole size and the flow velocity of the fluid. The calculation also considers the specific geometry for the segment in question. This would include borehole eccentricity and specific drill pipe geometry (box/pin upsets) that affect the flow velocity seen in the borehole annulus. The dynamic pressure calculation further includes cuttings accumulation downhole, as well as fluid rheology and the drill string movement's (penetration and rotation) effect on dynamic pressure of the fluid.

[0033] The pressure differential 262 for the entire annulus is calculated and compared to the set-point pressure 251 in the control module 264. The desired backpressure 266 is then determined and passed on to programmable logic controller 238, which generates control signals for the backpressure pump 128.

Calibration and Correction of the Backpressure

[0034] The above discussion of how backpressure is generally calculated utilized several downhole parameters, including downhole pressure and estimates of fluid viscosity and fluid density. These parameters are determined downhole and transmitted up the mud column using pressure pulses. Because the data bandwidth for mud pulse telemetry is very low and the bandwidth is used by other MWD/LWD functions, as well as drill string control functions, downhole pressure, fluid density and viscosity can not be input to the DAPC model on a real time basis. Accordingly, it will be appreciated that there is likely to be a difference between the measured downhole pressure, when transmitted up to the surface, and the predicted downhole pressure for that depth. When such occurs the DAPC system computes adjustments to the parameters and implements them in the model to make a new best estimate of downhole pressure. The corrections to the model may be made by varying any of the variable parameters. In the preferred embodiment, the fluid density and the fluid viscosity are modified in order to correct the predicted downhole pressure. Further, according to the present invention the actual downhole pressure measurement is used only to calibrate the calculated downhole pressure. It is not utilized to predict downhole annular pressure response. If downhole telemetry bandwidth increases, it may then be practical to include real time downhole pressure and temperature information to correct the model.

[0035] Because there is a delay between the measurement of downhole pressure and other real time inputs, the DAPC control system 236 further operates to index the inputs such that real time inputs properly correlate with delayed downhole transmitted inputs. The rig sensor inputs, calculated pressure differential and backpressure pressures, as well as the downhole measurements, may be "time-stamped" or "depth-stamped" such that the inputs and results may be properly correlated with later received downhole data. Utilizing a regression analysis based on a set of recently time-stamped actual pressure measurements, the model may be adjusted to more accurately predict actual pressure and the required backpressure.

[0036] Figure 5 depicts the operation of the DAPC control system demonstrating an uncalibrated DAPC model. It will be noted that the downhole pressure while drilling (PWD) 400 is shifted in time as a result of the time delay for the signal to be selected and transmitted uphole. As a result, there exists a significant offset between the DAPC predicted pressure 404 and the non-time stamped PWD 400. When the PWD is time stamped and shifted back in time 402, the differential between PWD 402 and the DAPC predicted pressure 404 is significantly less when compared to the non-time shifted PWD 400. Nonetheless, the DAPC predicted pressure differs significantly. As noted above, this differential is addressed by modifying the model inputs for fluid 150 density and viscosity. Based on the new estimates, in Fig. 6, the DAPC predicted pressure 404 more closely tracks the time stamped PWD 402. Thus, the DAPC model uses the PWD to calibrate the predicted pressure and modify model inputs to more accurately predict downhole pressure throughout the entire borehole profile.

[0037] Based on the DAPC predicted pressure, the DAPC control system 236 will calculate the required backpressure level 266 and transmit it to the programmable logic controller 240. The programmable controller 240 then generates the necessary control signals to choke 130, valves 121 and 123, and backpressure pump 128.

Applications of the DAPC System

[0038] The advantage in utilizing the DAPC backpressure system may be readily in the chart of Fig. 7. The hydrostatic pressure of the fluid is depicted in line 302. As may be seen, the pressure increases as a linear function of the depth of the borehole according to the simple formula:

Where P is the pressure, ρ is the fluid density, TVD is the total vertical depth of the well, and C is the backpressure. In the instance of hydrostatic pressure 302, the density is that of water. Moreover, in an open system, the backpressure C is zero. However, in order to ensure that the annular pressure 303 is in excess of the formation pore pressure 300, the fluid is weighted, thereby increasing the pressure applied as the depth increases. The pore pressure profile 300 can be seen in Fig. 7, linear, until such time as it exits casing 301, in which instance, it is exposed to the actual formation pressure, resulting in a sudden increase in pressure. In normal operations, the fluid density must be selected such that the annular pressure 303 exceeds the formation pore pressure below the casing 301.

[0039] In contrast, the use of the DAPC permits an operator to make essentially step changes in the annular pressure. Multiple DAPC pressure lines 304, 306, 308 and 310 are depicted in Fig. 7. In response to the pressure increase seen in the pore pressure at 300b, the back pressure C may be increased to step change the annular pressure from 304 to 306 to 308 to 310 in response to increasing pore pressure 300b, in contrast with normal annular pressure techniques as depicted in line 303. The DAPC concept further offers the advantage of being able to decrease the back pressure in response to a decrease in pore pressure as seen in 300c. It will be appreciated that the difference between the DAPC maintained annular pressure 310 and the pore pressure 300c, known as the overbalance pressure, is significantly less than the overbalance pressure seen using conventional annular pressure control methods 303. Highly overbalanced conditions can adversely affect the formation permeability be forcing greater amounts of borehole fluid into the formation.

[0040] Figure 8 is a graph depicting one application of the DAPC system in an At Balance Drilling (ABD) environment. The situation in Fig. 8 depicts the pore pressure in an interval 320a as being fairly linear until approximately 2 km TVD, and as being kept in check by conventional annular pressure 321a. At 2 km TVD a sudden increase in pore pressure occurs at 320b. Utilizing present techniques, the answer would be to increase the fluid density to prevent formation fluid influx and sloughing off of the borehole mud cake. The resulting increase in density modifies the pressure profile applied by the fluid to 321b. However, in doing so it dramatically increases the overbalance pressure, not only in region 320c, but in region 320a as well.

[0041] Using the DAPC technique, the alternative response to the pressure increase seen at 320b, would be to apply backpressure to the fluid to shift the pressure profile to the right, such that pressure profile 322 more closely matches the pore pressure 320c, as opposed to pressure profile 321b.

[0042] The DAPC method of pressure control may also be used to control a major well event, such as a fluid influx. Under present methods, in the event of a large formation fluid influx, such as a gas kick, the only option was to close the BOPs to effectively to shut in the well, relieve pressure through the choke and kill manifold, and weight up the drilling fluid to provide additional annular pressure. This technique requires time to bring the well under control. An alternative method is sometimes called the "Driller's" method, which utilizes continuous circulation without shutting in the well. A supply of heavily weighted fluid, e.g., 18 pounds per gallon (ppg) (3.157 kg/l) is constantly available during drilling operations below any set casing. When a gas kick or formation fluid influx is detected, the heavily weighted fluid is added and circulated downhole, causing the influx fluid to go into solution with the circulating fluid. The influx fluid starts coming out of solution upon reaching the casing shoe and is released through the choke manifold. It will be appreciated that while the Driller's method provides for continuous circulation of fluid, it may still require additional circulation time without drilling ahead, to prevent additional formation fluid influx and to permit the formation fluid to go into circulation with the now higher density drilling fluid.

[0043] Utilizing the present DAPC technique, when a formation fluid influx is detected, the backpressure is increased, as opposed to adding heavily weighted fluid. Like the Driller's method, the circulation is continued. With the increase in pressure, the formation fluid influx goes into solution in the circulating fluid and is released via the choke manifold. Because the pressure has been increased, it is no longer necessary to immediately circulate a heavily weighted fluid. Moreover, since the backpressure is applied directly to the annulus, it quickly forces the formation fluid to go into solution, as opposed to waiting until the heavily weighted fluid is circulated into the annulus.

[0044] An additional application of the DAPC technique relates to its use in noncontinuous circulating systems. As noted above, continuous circulation systems are used to help stabilize the formation, avoiding the sudden pressure 502 drops that occurs when the mud pumps are turned off to make/break new pipe connections. This pressure drop 502 is subsequently followed by a pressure spike 504 when the pumps are turned back on for drilling operations. This is depicted in Fig. 9A. These variations in annular pressure 500 can adversely affect the borehole mud cake, and can result in fluid invasion into the formation. As shown in Fig. 9B, the DAPC system backpressure 506 may be applied to the annulus upon shutting off the mud pumps, ameliorating the sudden drop in annulus pressure from pump off condition to a more mild pressure drop 502. Prior to turning the pumps on, the backpressure may be reduced such that the pump on condition spike 504 is likewise reduced. Thus the DAPC backpressure system is capable of maintaining a relatively stable downhole pressure during drilling conditions. Although the invention has been described with reference to a specific embodiment, it will be appreciated that modifications may be made to the system and method described herein without departing from the invention.

Claims

1. A system for controlling formation pressure during the drilling of a subterranean formation, comprising:

a drill string (112) extending into a borehole, the drill string including a bottom hole assembly (113) comprising a drill bit (120);

a primary pump (138) for selectively pumping a drilling fluid from a drilling fluid source (150), through said drill string (112), out said drill bit (120) and into an annular space (115) created as said drill string (112) penetrates the formation;

a fluid discharge conduit (124) in fluid communication with said annular space for discharging said drilling fluid to a reservoir (150) to clean said drilling fluid for reuse;

a fluid backpressure system connected to said fluid discharge conduit; said fluid backpressure system comprised of a fluid choke (130), a backpressure pump (128), a fluid source (150), whereby said backpressure pump (128) may be selectively activated to increase annular space drilling fluid pressure;

characterized by:

a sensor (116) and a telemetry system (119) comprised in the bottom hole assembly, capable of receiving and transmitting data, including sensor data, said sensor data including at least pressure data;

a surface telemetry system for receiving data and transmitting commands to the bottom hole assembly;

a flow meter (126) comprised in the backpressure system;

a pressure monitoring and control system (146) capable of receiving information related to the borehole, drill rig and drilling fluid as inputs to a model to predict downhole pressure and of utilizing the information to predict down hole pressure for continued drilling and of comparing the predicted down hole pressure to a desired downhole pressure, and of utilizing the differential to control the fluid backpressure system,

wherein the pressure monitoring and control system (146) is in communication with the surface telemetry system and capable of utilizing actual down hole pressure data to calibrate the model by modifying input parameters to more closely correlate the predicted downhole pressure to the actual down hole pressure data.

2. The system of claim 1, wherein the pressure monitoring system (146) is capable of receiving drilling operational data, said drilling operational data including drill string weight on bit, drill string torque on bit, drilling fluid weight, drilling fluid volume, primary and backpressure pump pressures, drilling fluid flow rates, drill string rate of penetration, drill string rotation rate, and sensor data transmitted by said bottom hole assembly.

3. The system of claim 2, wherein said pressure monitoring and control system (146) utilizes said drilling operational data to
monitor existing said annular space pressures during drilling operations;
model borehole expected pressures for continued drilling; and
control said primary pump and fluid backpressure system in response to existing annular pressures and borehole expected pressures.

4. The system of claim 3, wherein said pressure monitoring and control system (146) further includes communication means (240), processing means (236), and control means (230) for controlling said primary pump (138) and fluid backpressure system.

5. The system of claim 1, wherein said fluid backpressure system fluid source is said drilling fluid source.

6. The system of claim 1, wherein said fluid backpressure system fluid source is said fluid discharge outlet.

7. The system of any one of the previous claims, wherein the sensor data further includes temperature data.

8. A method for controlling formation pressure during the drilling of a subterranean formation, the method comprising the steps:

deploying a drill string (112) extending into a borehole, the drill string including a bottom hole assembly (113) comprising a drill bit (120);

selectively pumping a drilling fluid utilizing a primary pump (138) from a drilling fluid source (150), through said drill string (112), out said drill bit (120) and into an annular space (115) created as said drill string penetrates the formation;

discharging said drilling fluid from said annular space (115) through a fluid discharge conduit (124) to a reservoir (150) to clean said drilling fluid for reuse;

selectively increasing annular space drilling fluid pressure utilizing a fluid backpressure system connected to said fluid discharge conduit;

characterized by:

a sensor (116) and a telemetry system (119) comprised in the bottom hole assembly, capable of receiving and transmitting data, including sensor data, said sensor data including at least pressure data;

providing a surface telemetry system for receiving data and transmitting commands to the bottom hole assembly;

utilizing information related to the wellbore, drill rig and drilling fluid as inputs to a model to predict downhole pressure, utilizing the information to predict down hole pressure for continued drilling and comparing the predicted down hole pressure to a desired downhole pressure, and utilizing the differential to control the fluid backpressure system,

wherein actual down hole pressure data is utilized to calibrate the model and to modify input parameters to more closely correlate predicted downhole pressures to the actual down hole pressures.

9. The method of claim 8, further providing a pressure monitoring system (146) for receiving drilling operational data, said drilling operational data including drill string weight on bit, drill string torque on bit, drilling fluid weight, drilling fluid volume, primary and backpressure pump pressures, drilling fluid flow rates, drill string rate of penetration, drill string rotation rate, and sensor data transmitted by said bottom hole assembly.

10. The method of claim 9, wherein said pressure monitoring system (146), utilizing said drilling operational data, further monitors existing said annular space pressures during drilling operations;
models borehole expected pressures for continued drilling; and
controls said primary pump (138) and fluid backpressure system in response to existing annular pressures and borehole expected pressures.

11. The method of claim 10, wherein said pressure monitoring system (146) further includes communication means (240), processing means (236), and control means (230) for controlling said primary pump (138) and fluid backpressure system.

12. The method of claim 8, wherein said fluid backpressure system fluid source is said drilling fluid source.

13. The method of claim 8, wherein said fluid backpressure system fluid source is said fluid discharge outlet.

Ansprüche

1. System zum Steuern des Formationsdruckes während des Bohrens einer unterirdischen Formation, mit:

einem Bohrgestänge (112), das sich in ein Bohrloch erstreckt, wobei das Bohrgestänge eine Bohrlochbodenanordnung (113) umfaßt, die mit einem Bohrmeißel (120) versehen ist;

einer Hauptpumpe (138) zum selektiven Pumpen eines Bohrfluids von einer Bohrfluidquelle (150) durch das Bohrgestänge (112), aus dem Bohrmeißel (120) hinaus und in einen Ringraum (115), der beim Eindringen des Bohrgestänges (112) in die Formation erzeugt wird;

einer Fluidaustragleitung (124) in Fluidverbindung mit dem Ringraum zum Austragen des Bohrfluids in ein Reservoir (150) zum Reinigen des Bohrfluids zur Wiederverwendung;

einem Fluidgegendrucksystem, das an die Fluidaustragleitung angeschlossen ist; wobei das Fluidgegendrucksystem eine Fluiddrossel (130), eine Gegendruckpumpe (128) und eine Fluidquelle (150) aufweist, wobei die Gegendruckpumpe (128) selektiv betätigt werden kann, um den Bohrfluiddruck im Ringraum zu erhöhen;

gekennzeichnet durch:

einen Sensor (116) und ein Telemetriesystem (119), die in der Bohrlochbodenanordnung enthalten und befähigt sind, Daten zu empfangen und zu übertragen, einschließlich Sensordaten, wobei die Sensordaten zumindest Druckdaten enthalten;

ein Oberflächentelemetriesystem zum Empfangen der Daten und zum Übertragen von Befehlen an die Bohrlochbodenanordnung;

einen Strömungsmesser (126), der in dem Gegendrucksystem enthalten ist;

ein Drucküberwachungs- und Steuerungssystem (146), das befähigt ist, auf das Bohrloch, den Bohrturm und das Bohrfluid bezugnehmende Information als Eingänge für ein Modell zur Vorhersage des Bohrlochdruckes zu empfangen, die Information zur Vorhersage des Bohrlochbodendruckes für ein fortgesetztes Bohren zu verwenden und den vorhergesagten Bohrlochbodendruck mit einem erwünschten Bohrlochbodendruck zu vergleichen, um das Differential zur Steuerung des Fluidgegendrucksystems zu verwenden,

bei welchem das Drucküberwachungs- und Steuerungssystem (146) mit dem Oberflächentelemetriesystem in Kommunikation und befähigt ist, die tatsächlichen Bohrlochdruckdaten zu verwenden, um das Modell zu kalibrieren, indem die Eingangsparameter modifiziert werden, damit sie dem vorhergesagten Bohrlochdruck hinsichtlich der tatsächlichen Bohrlochdruckdaten genauer entsprechen.

2. System nach Anspruch 1, bei welchem das Drucküberwachungssystem (146) befähigt ist, die Bohrbetriebsdaten zu empfangen, wobei die Bohrbetriebsdaten, einschließlich des Gewichtes des Bohrgestänges auf den Bohrmeißel, das Bohrgestängedrehmoment auf den Meißel, das Gewicht des Bohrfluids, das Bohrfluidvolumen, die Drücke der Hauptpumpe und der Gegendruckpumpe, die Bohrfluidströmungsraten, die Bohrgestängeeindringrate, die Bohrgestängedrehrate und die Sensordaten von der Bohrlochbodenanordnung übertragen werden.

3. System nach Anspruch 2, bei welchem das Drucküberwachungs- und Steuerungssystem (146) die Bohrbetriebsdaten verwendet, um den existierenden Ringraumdruck während der Bohrvorgänge zu überwachen;
den erwarteten Druck im Bohrloch für ein fortgesetztes Bohren zu modellieren; und die Hauptpumpe und das Fluidgegendrucksystem in Abhängigkeit von den bestehenden Ringraumdrücken und den erwarteten Bohrlochdrücken zu steuern.

4. System nach Anspruch 3, bei welchem das Drucküberwachungs- und Steuerungssystem (146) ferner Kommunikationsmittel (240), Prozessormittel (236) und Steuermittel (230) zur Steuerung der Hauptpumpe (138) und des Fluidgegendrucksystems aufweist.

5. System nach Anspruch 1, bei welchem die Fluidquelle für das Fluidgegendrucksystem die Bohrfluidquelle ist.

6. System nach Anspruch 1, bei welchem die Fluidquelle für das Fluidgegendrucksystem der Fluidaustragauslaß ist.

7. System nach einem der vorhergehenden Ansprüche, bei welchem die Sensordaten ferner Temperaturdaten umfassen.

8. Verfahren zum Steuern des Formationsdruckes während des Bohrens einer unterirdischen Formation, wobei das Verfahren die Schritte aufweist:

Einsetzen eines Bohrgestänges (112), das sich in ein Bohrloch erstreckt, wobei das Bohrgestänge eine Bohrlochbodenanordnung (113) aufweist, die mit einem Bohrmeißel (120) versehen ist;

selektives Pumpen eines Bohrfluids unter Verwendung einer Hauptpumpe (138) von einer Bohrfluidquelle (150) durch das Bohrgestänge (112), aus dem Bohrmeißel (120) heraus und in einen Ringraum (115), der erzeugt wird, wenn das Bohrgestänge in die Formation eindringt;

Austragen des Bohrfluids aus dem Ringraum (115) durch eine Fluidaustragleitung (124) in ein Reservoir (150) zum Reinigen des Bohrfluids zur Wiederverwendung;

selektives Erhöhen des Bohrfluiddruckes im Ringraum unter Verwendung eines Fluidgegendrucksystems, das mit der Fluidaustragleitung verbunden ist;

gekennzeichnet durch:

einen Sensor (116) und ein Telemetriesystem (119), die in der Bohrlochbodenanordnung enthalten sind, wobei sie befähigt sind, Daten aufzunehmen und zu übertragen, einschließlich Sensordaten, wobei die Sensordaten zumindest Druckdaten umfassen;

Vorsehen eines Oberflächentelemetriesystems zum Empfangen der Daten und zum Übertragen von Befehlen an die Bohrlochbodenanordnung;

Verwendung der Information betreffend das Bohrloch, den Bohrturm, das Bohrfluid als Eingänge für ein Modell zur Vorhersage des Bohrlochdruckes, Verwendung der Information zur Vorhersage des Bohrlochbodendruckes für ein fortgesetztes Bohren, und Vergleichen des vorhergesagten Bohrlochbodendruckes mit einem erwünschten Bohrlochbodendruck, sowie Verwendung des Differentials zur Steuerung des Fluidgegendrucksystems,

bei welchem die tatsächlichen Bohrlockdruckdaten verwendet werden, um das Modell zu kalibrieren und die Eingangsparameter zu modifizieren, damit die vorhergesagten Bohrlochdrücke den gemessenen Bohrlochdrücken genauer entsprechen.

9. Verfahren nach Anspruch 8, bei welchem ferner ein Drucküberwachungssystem (146) zum Empfangen der Bohrbetriebsdaten vorgesehen ist, wobei die Bohrbetriebsdaten das Gewicht des Bohrgestänges auf den Bohrmeißel, das Bohrgestängedrehmoment auf den Bohrmeißel, das Gewicht des Bohrfluids, das Bohrfluidvolumen, die Drücke der Hauptpumpe und der Gegendruckpumpe, die Bohrfluidströmungsraten, die Eindringrate des Bohrgestänges, die Drehungsrate des Bohrgestänges und die Sensordaten, die von der Bohrlochbodenanordnung übertragen werden, umfassen.

10. Verfahren nach Anspruch 9, bei welchem das Drucküberwachungssystem (146), welches die Bohrlochbetriebsdaten umfaßt, ferner
die existierenden Ringraumdrücke während der Bohrvorgänge überwacht;
die erwarteten Drücke im Bohrloch für ein fortgesetztes Bohren modelliert; und
die Hautpumpe (138) und das Fluidgegendrucksystem in Abhängigkeit von den bestehenden Ringraumdrücken und den erwarteten Bohrlochdrücken steuert.

11. Verfahren nach Anspruch 10, bei welchem das Drucküberwachungssystem (146) ferner Kommunikationsmittel (240), Prozessormittel (236) und Steuermittel (230) zur Steuerung der Hauptpumpe (138) und des Fluidgegendrucksystems umfaßt.

12. Verfahren nach Anspruch 8, bei welchem die Fluidquelle des Fluidgegendrucksystems die Bohrfluidquelle ist.

13. Verfahren nach Anspruch 8, bei welchem die Fluidquelle des Fluidgegendrucksystems der Fluidaustragauslaß ist.

Revendications

1. Système pour contrôler une pression de formation pendant le forage d'une formation souterraine, comprenant:

un train de tiges (112) qui s'étend dans un trou de forage, le train de tiges incluant une unité de fond de trou (113) comprenant un outil de forage (120),

une pompe primaire (138) pour pomper de manière sélective un fluide de forage à partir d'une source de fluide de forage (150), à travers ledit train de tiges (112), hors de l'outil de forage (120) et dans un espace annulaire (115) créé lorsque ledit train de tiges (112) pénètre la formation,

un conduit de déchargement de fluide (124) en communication pour fluide avec ledit espace annulaire pour décharger ledit fluide de forage dans un réservoir (150) pour nettoyer ledit fluide de forage pour réutilisation,

un système de contre-pression de fluide relié audit conduit de déchargement de fluide, ledit système de contre-pression de fluide comprenant un étrangleur pour fluide (130), une pompe de contre-pression (128), une source de fluide (150), ladite pompe de contre-pression (128) pouvant être activée de manière sélective pour augmenter la pression de fluide de forage de l'espace annulaire,

caractérisé par

un détecteur (116) et un système de télémétrie (119) prévus dans l'unité de fond de trou, capables de recevoir et de transmettre des données, incluant des données de détecteur, lesdites données de détecteur incluant au moins des données de pression,

un système de télémétrie de surface pour recevoir des données et transmettre des commandes à l'unité de fond de trou,

un débitmètre (126) prévu dans le système de contre-pression,

un système de surveillance et de contrôle de pression (146) capable de recevoir une information relative au trou de forage, à la tour de forage et au fluide de forage, comme entrées dans un modèle de prédiction de la pression en bas du trou et d'utiliser l'information pour prédire la pression en bas du trou pour une poursuite du forage et de comparer la pression en bas du trou prédite à une pression en bas du trou souhaitée, et d'utiliser le différentiel pour contrôler le système de contre-pression de fluide,

dans lequel le système de surveillance et de contrôle de pression (146) est en communication avec le système de télémétrie de surface et est capable d'utiliser des données de pression en bas du trou réelles pour calibrer le modèle en modifiant des paramètres d'entrée pour corréler de manière plus étroite la pression en bas du trou prédite aux données de pression en bas du trou réelles.

2. Système selon la revendication 1, dans lequel le système de surveillance de pression (146) est capable de recevoir des données opérationnelles de forage, lesdites données opérationnelles de forage incluant le poids du train de tiges sur l'outil, le couple de torsion du train de tiges sur l'outil, le poids du fluide de forage, le volume du fluide de forage, les pressions de pompe primaire et de pompe de contre-pression, des débits de fluide de forage, la vitesse de pénétration du train de tiges, la vitesse de rotation du train de tiges, et des données de détecteur transmises par ladite unité de fond de trou.

3. Système selon la revendication 2, dans lequel ledit système de surveillance et de contrôle de pression (146) utilise lesdites données opérationnelles de forage
pour surveiller l'existence desdites pressions d'espace annulaire pendant des opérations de forage,
pour modéliser des pressions attendues dans le trou de forage pour une poursuite du forage, et
pour contrôler ladite pompe primaire et ledit système de contre-pression de fluide en réponse à des pressions annulaires existantes et des pressions attendues dans le trou de forage.

4. Système selon la revendication 3, dans lequel ledit système de surveillance et de contrôle de pression (146) inclut en outre des moyens de communication (240), des moyens de traitement (236) et des moyens de contrôle (230) pour contrôler ladite pompe primaire (138) et ledit système de contre-pression de fluide.

5. Système selon la revendication 1, dans lequel ladite source de fluide du système de contre-pression de fluide est ladite source de fluide de forage.

6. Système selon la revendication 1, dans lequel ladite source de fluide du système de contre-pression de fluide est ladite sortie de déchargement de fluide.

7. Système selon l'une quelconque des revendications précédentes, dans lequel les données de détecteur incluent en outre des données de température.

8. Procédé pour contrôler une pression de formation pendant le forage d'une formation souterraine, le procédé comprenant les étapes:

de déploiement d'un train de tiges (112) qui s'étend dans un trou de forage, le train de tiges incluant une unité de fond de trou (113) comprenant un outil de forage (120),

de pompage de manière sélective d'un fluide de forage en utilisant une pompe primaire (138) à partir d'une source de fluide de forage (150), au travers dudit train de tiges (112), hors dudit outil de forage (120) et dans un espace annulaire (115) créé lorsque ledit train de tiges pénètre la formation,

de déchargement dudit fluide de forage à partir dudit espace annulaire (115) à travers un conduit de déchargement de fluide (124) jusqu'à un réservoir (150) pour nettoyer ledit fluide de forage pour réutilisation,

d'augmentation de manière sélective d'une pression de fluide de forage dans l'espace annulaire en utilisant un système de contre-pression de fluide relié audit conduit de déchargement de fluide,

caractérisé par

un détecteur (116) et un système de télémétrie (119) prévus dans l'unité de fond de trou et capables de recevoir et de transmettre des données, incluant des données de détecteur, lesdites données de détecteur incluant au moins des données de pression,

fournir un système de télémétrie de surface pour recevoir des données et transmettre des commandes à l'unité de fond de trou,

utiliser une information relative au trou de forage, à la tour de forage et au fluide de forage comme entrées dans un modèle pour prédire une pression en bas du trou, utiliser l'information pour prédire une pression en bas du trou pour une poursuite du forage et comparer la pression en bas du trou prédite à une pression en bas du trou souhaitée, et utiliser le différentiel pour contrôler le système de contre-pression de fluide,

dans lequel des données de pression en bas du trou réelles sont utilisées pour calibrer le modèle et pour modifier des paramètres d'entrée pour corréler de manière plus étroite des pressions en bas du trou prédites aux pressions en bas du trou réelles.

9. Procédé selon la revendication 8, comprenant en outre de fournir un système de surveillance de pression (146) pour recevoir des données opérationnelles de forage, lesdites données opérationnelles de forage incluant le poids du train de tiges sur l'outil, le couple de torsion du train de tiges sur l'outil, le poids du fluide de forage, le volume du fluide de forage, les pressions de pompe primaire et de pompe de contre-pression, les débits de fluide de forage, la vitesse de pénétration du train de tiges, la vitesse de rotation du train de tiges et des données de détecteur transmises par ladite unité de fond de trou.

10. Procédé selon la revendication 9, dans lequel lesdits systèmes de surveillance de pression (146) faisant usage desdites données opérationnelles de forage,
surveillent en outre l'existence desdites pressions d'espace annulaire pendant des opérations de forage,
modélisent des pressions attendues dans le trou de forage pour une poursuite du forage, et
contrôlent ladite pompe primaire (138) et ledit système de contre-pression de fluide en réponse à des pressions annulaires existantes et des pressions attendues du trou de forage.

11. Procédé selon la revendication 10, dans lequel ledit système de surveillance de pression (146) inclut en outre des moyens de communication (240), des moyens de traitement (236) et des moyens de contrôle (230) pour contrôler ladite pompe primaire (138) et ledit système de contre-pression de fluide.

12. Procédé selon la revendication 8, dans lequel ladite source de fluide du système de contre-pression de fluide est ladite source de fluide de forage.

13. Procédé selon la revendication 8, dans lequel ladite source de fluide du système de contre-pression de fluide est ladite sortie de déchargement de fluide.

Drawing