Patent Description:
Some reservoirs are located in carbonate formations, which are severely fractured with natural fractures, karsts, vugs, or caves. These carbonate reservoirs make up about <NUM>% of all global reservoirs and make up approximately <NUM>% of worldwide oil and gas reserves. Due to their prevalence, operators seek ways to drill to target depths in these naturally-fractured carbonate formations. Unfortunately, well control can be complicated when drilling in these carbonate formations because the fractures in the formations can cause severe loss of circulation followed by fluid influx.

Currently, operators use mud-cap drilling (MCD) to drill in carbonate formations and try to keep up with the loss of circulation to the formation. This practice may not be feasible in some situations and cannot be performed in certain areas. There are several forms of mud cap drilling, including Pressurized Mud Cap Drilling (PMCD) also known as Closed Hole Circulation Drilling (CHCD) and Floating Mud Cap Drilling (FMCD).

Pressurized Mud Cap Drilling (PMCD) is a drilling technique used to drill without returns. An example implementation of Pressurized Mud Cap Drilling (PMCD) is disclosed in <CIT>. Floating Mud Cap Drilling (FMCD) is another drilling technique used to drill without returns. Sacrificial fluid is continuously pumped down the drillstring and the annulus to prevent formation fluid from migrating to the
surface. Another document describing PMCD is e.g. the paper <NPL>et al.

In pressurized mud cap drilling, a rotating control device is used while drilling the wellbore and pumping a sacrificial fluid (e.g., water) down the drillpipe. At the same time, a pressurized mud-cap of weighted oil-based mud (OBM) is kept in the annulus to control possible fluid influx.

In general, mud cap drilling allows everything pumped into the wellbore along with drilling cuttings to be injected into the open-hole formation, while a fluid column of a Light Annular Mud (LAM) cap is maintained above the open-hole formation. Additional fluid can be periodically added into the annulus to control the surface back pressure within the operating limits of a rotating control device and/or a riser of the drilling system. In this way, the mud cap maintained in the annulus of the wellbore during drilling can stabilize the borehole and control the well.

Briefly, <FIG> illustrates a wellbore <NUM> being drilled using pressurized mud cap drilling according to the prior art. A drilling system <NUM> has a drilling string <NUM> having a float valve <NUM> and a bottom hole assembly <NUM>. The system <NUM> drills in an open hole <NUM> of the wellbore <NUM>. The bottom hole assembly <NUM> has reached a total loss zone <NUM> (a. theft zone) having natural fracture(s) <NUM>. The annulus <NUM> of the wellbore <NUM> is closed off from surface using a rotating control device <NUM>. In this way, no returns are brought to surface.

Instead, a sacrificial fluid <NUM> is pumped down the drillstring <NUM>, and a mud cap <NUM> is placed in the annulus <NUM> surrounding the drillstring <NUM>. The float valve <NUM> prevents fluid flow back up the drillstring <NUM>, such as during connections of drillpipe. The mud cap <NUM> caps off the open hole <NUM> and prevents the flow of returns upwards through the annulus <NUM>. Consequently, the returns and any cuttings flow into the formation at the loss circulation zone <NUM> having the natural fracture(s) <NUM>.

In the pressurized mud cap drilling (PMCD), pressure management is achieved using the pump rates of the sacrificial fluid <NUM> drilling system <NUM>. The light annular fluid for the mud cap <NUM> is pumped at a rate that overcomes gas/fluid migration rate down the annulus <NUM> at just below reservoir pressure to maintain the hole filled and to prevent annular gas migration. However, the sacrificial fluid (e.g., water) is pumped down the drillstring <NUM> at high pump rates. Consequently, the mud cap <NUM> increases the bottomhole pressure, while the sacrificial fluid <NUM> pumped down the drillstring <NUM> and into the open hole <NUM> is lost to the theft zone <NUM>. In this way, annular backpressure can be used to balance the reservoir pressure and maintain system balance.

The light annular fluid for the mud cap <NUM> has a mud weight that is less than a mud weight of the formation fluid in the open hole <NUM>. (As is known, mud weight is the mass per unit volume for a fluid and can be given as mass pounds (Ibm) per gallon (ppg) or kilograms per cubic meter (kg/m<NUM>)). A typical mud weight of the light annular mud may be about <NUM>,<NUM>/m<NUM> (<NUM>-ppg (pounds per gallon)). As is known, the hydrostatic pressure produced by a column of mud cap <NUM> in the wellbore annulus <NUM> is a product of the pressure gradient of the fluid used and the vertical height of the fluid column. The pressure gradient of the fluid is typically given as a unit pressure per unit height (e.g., psi per foot) and is converted from the mud weight of the fluid, which is typically given in pounds-per-gallon, by a conversion factor (e.g., <NUM> psi per foot equals <NUM> pounds per gallon).

Although lower mud weights are possible, the lower weight fluids may require complex chemistries and additives that may not always be available on site or may not be feasible for use in a given implementation. Accordingly, a conventional light annular fluid of about <NUM>,<NUM>/m<NUM> (<NUM>-ppg) can be used for open holes that have weights that are only slightly higher (e.g., <NUM>,<NUM>/m<NUM> (<NUM>-ppg)).

To maintain the balance, operators look for a measurable pressure at the rotating control device <NUM> while pumping the sacrificial fluid <NUM> down the drillstring <NUM>. As the pressurized mud cap drilling continues, the pressure value at the rotating control device <NUM> is monitored to maintain a reading within a desired threshold while the annulus <NUM> is kept full with the mud cap <NUM> of light annular mud. This allows operators to monitor the annular backpressure used to balance the reservoir pressure and maintain system balance.

Although mud cap drilling may be effective, most of the major carbonate reservoirs where it can be used are approaching their depletion phases. Once depleted, the reservoir pressure cannot even hold a mud column used in mud cap drilling. For example, a relatively depleted reservoir may have a reservoir pressure associated with a pressure gradient from a mud weight of less than <NUM>,<NUM>/m<NUM> (<NUM>-ppg). Application of pressurized mud cap drilling may therefore no longer be feasible because the reservoir pressure cannot hold the hydrostatic pressure of a column of the lightest available base fluid for the light annulus mud (LAM) in the mud cap <NUM>.

For instance, the mud weight of sea water is approximately <NUM>,<NUM>/m<NUM> (<NUM>-ppg), while the mud weight of fresh water is about <NUM>/m<NUM> (<NUM>-ppg). In many cases, the lightest mud available at a drill site without expensive chemistry and additives may have a mud weight of about <NUM>/m<NUM> (<NUM>-ppg). In other words, the open hole <NUM> may have a theft zone <NUM> with a formation pressure associated with a mud weight less than <NUM>,<NUM>/m<NUM> (<NUM>-ppg) (the mud weight of seawater) so that pressurized mud cap drilling with a mud cap of lighter density fluid may not be possible or practical. Therefore, operators need a new solution to drill low or subnormal pressure wells found in relatively depleted reservoirs.

The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

A method of drilling a wellbore in a formation of a reservoir is disclosed herein. The reservoir may be a low or subnormal pressure reservoir.

According to a first aspect there is provided a method according to appended claim <NUM>. In the method, instrumentation is associated with casing disposed in the wellbore. An open hole section of the wellbore is drilled, in a first stage, in the formation for an extent beyond the casing by pumping drilling fluid at a drilling rate through a drillstring and allowing returns of the drilling fluid to surface through an annulus between the wellbore and the drillstring. During the first stage of drilling, a static loss rate of the drilling fluid to the formation is detected to reach within a loss circulation limit of the drilling rate. In response to the detection, (a) the annulus of the wellbore is filled with a mud cap of annulus fluid up to a flow control device, (b) it is determined that the annulus cannot be kept filled with the annulus fluid up to the flow control device, (c) the annulus fluid in the annulus is allowed to balance with reservoir pressure, and (d) an initial fluid level, below the flow control device where the mud cap is balanced with the reservoir pressure, is defined in the annulus by monitoring pressure in the annulus using the instrumentation.

The open hole section of the wellbore is drilled, in a second stage, in the formation for a subsequent extent beyond the casing while the annulus is filled with the mud cap to the initial fluid level by: pumping a sacrificial fluid through the drillstring without returns to surface through the annulus, and monitoring the mud cap in the annulus by monitoring pressure using the instrumentation to detect a change relative to the initial fluid level. The drilling is then controlled in response to the detected change.

To detect that the static loss rate of the drilling fluid reaches within the loss circulation limit of the drilling rate, the method can detect that the static loss rate of the drilling fluid reaches within at least half of the circulation at the drilling rate.

According to one arrangement of the method, various steps can be performed before the step (a) of filling the annulus of the wellbore with the mud cap of the annulus fluid up to the flow control device in response to the detection. In particular, the method can comprise closing off the annulus to returns with a flow control device. For example, a rotating control device can be installed that isolates the annulus in the wellbore from the surface.

The method can further comprise the step of drilling in an intermediate stage, after the first stage but before the second stage, by pumping the sacrificial fluid through the drillstring without returns to surface through the annulus and keeping the annulus filled with the mud cap up to the flow control device to maintain a pressure of the mud cap in the annulus at the flow control device.

At some point in this intermediate stage, a determination can be made that the annulus cannot be kept filled with the mud cap up to the flow control device. The drilling is stopped in the intermediate stage, and the mud cap in the annulus is allowed to balance with the reservoir pressure to a state that defines the initial fluid level of the mud cap in the annulus below the flow control device. The second stage discussed previously can then follow in the method given the defined initial fluid level.

For example, in determining that the annulus cannot be kept filled with the annulus fluid, a determination can be made (i) that the wellbore cannot be kept full using a lightest one of the annulus fluid available at a rig site, and/or (ii) that a pump rate for pumping the sacrificial fluid exceeds a pump rate limit.

To allow the annulus fluid in the annulus to balance with the reservoir pressure, the pumping of the sacrificial fluid can be stopped, a current level of the annulus fluid can be allowed to drop in the wellbore until stabilized. Stabilization can be established by: measuring a pressure of the annulus fluid in the annulus until the pressure stabilizes to within a pressure margin; and/or monitoring the current level until the current level stabilizes to within a level margin.

In providing the instrumentation associated with the casing, the instrumentation can be provided as part of an isolation valve disposed on the casing in the wellbore. The instrumentation can comprise a pressure sensor measuring an annulus pressure at a depth in the wellbore, the measured pressure being used to determine the initial fluid level of the mud cap in the annulus of the wellbore.

Depending on the behavior and the detected change, the control of drilling can take a number of forms. In one form of control, a determination can be made that the detected change falls within a threshold. The drilling of the wellbore can be continued by pumping the sacrificial fluid through the drillstring without the returns to surface through the annulus, and the method can return to monitoring the mud cap in the annulus to detect a subsequent change relative to the initial fluid level.

In another form of control, the drilling can be stopped, the pumping of the sacrificial fluid down the drillstring can be turned off.

In yet another form of control, a determination can be made that the detected change comprises an increase of the mud cap from the initial fluid level by detecting an increase in pressure measured at a depth in the annulus, and a determination can be made that the pressure measured at the depth in the annulus stops increasing and then decreases. The method can then convert from drilling the wellbore with the mud cap to drilling a further extent of the wellbore with a different drilling procedure.

In another form of control, a determination can be made that the detected change comprises an increase in the level of the mud cap from the initial fluid level by detecting an increase in pressure measured at a depth in the annulus, and a determination can be made that the pressure measured at the depth in the annulus stops increasing but does not decrease. The method can then re-evaluate the initial fluid level of the mud cap and commence the drilling of a further extent of the wellbore with the mud cap at the re-evaluated fluid level.

In yet another form of control, a determination can be made that the detected change comprises an increase in the level of the mud cap from the initial fluid level, and a determination can be made that pressure measured in the annulus continues increasing. The method can then involve bullheading the wellbore.

In still another form of control, a determination can be made that the detected change comprises a decrease in the level of the mud cap from the initial fluid level by detecting a decrease in pressure measured at a depth in the annulus, and the method may involve bullheading the wellbore.

In another form of control, a determination can be made that the detected change comprises an increase in the level of the mud cap from the initial fluid level. The method can measure for a temperature change in the annulus fluid at a depth in the annulus indicative of migration of formation gas in the mud cap; and the wellbore can be bullheaded in response to the measured temperature change indicative of the formation gas migration in the mud cap.

In yet another form of control, a determination can be made that the detected change comprises an increase in the level of the mud cap from the initial fluid level. The method can measure for a presence of a gas in the annular fluid at a depth in the annulus indicative of migration of formation gas in the mud cap; and the wellbore can be bullheaded in response to the measured presence of the gas indicative of the formation gas migration in the mud cap.

According to a second aspect there is provided a system according to appended claim <NUM>.

According to a third aspect there is provided a programmable storage device according to appended claim <NUM>.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

<FIG> illustrate a wellbore <NUM> being drilled in an initial stage of a process of closed hole circulation drilling with continuous downhole monitoring according to the present disclosure. The wellbore <NUM> is being drilled using a drilling system <NUM> having a drilling string <NUM>, a float valve <NUM>, and a bottom hole assembly <NUM>. The system <NUM> drills with the bottom hole assembly <NUM> in an open hole section <NUM> of the wellbore <NUM>, and the float valve <NUM> prevents fluid flow back up the drillstring <NUM>, such as during connections of drillpipe.

Overall, the drilling system <NUM> may be an offshore system or a land-based system. As an offshore system, the drilling system <NUM> may be implemented on a floating platform or mobile offshore drilling unit (MODU) and may use a riser (not shown) connected to a subsea Blow-Out-Preventer on a wellhead (not shown) at the sea floor. Overall, the drilling system <NUM> can include any of the conventional equipment of a rig assembly for running, rotating, and tripping the drillstring <NUM> and for handling fluid.

In general, the drilling system <NUM> includes fluid handling equipment to handle fluid in the drillstring <NUM> and in the annulus <NUM> between the drillstring <NUM> and the wellbore. For example, one or more pumps <NUM> are operable to pump fluid from one or more sources <NUM> into the drilling string <NUM> and the annulus <NUM>. As discussed below, the fluid sources <NUM> at least include a sacrificial fluid and a drilling fluid. Instrumentation <NUM> associated with the casing <NUM> disposed in the wellbore <NUM> is configured to measure parameters in the annulus <NUM>. The instrumentation <NUM> at least includes one or more pressure sensor s64 that can measure pressure of the fluid in the annulus <NUM>, as discussed below.

In the initial stage of <FIG>, the system <NUM> may be drilling the wellbore <NUM> in a conventional manner. Depending on the drilling environment, for example, the system <NUM> may or may not include a flow control device (not shown in <FIG>) to isolate the annulus <NUM> from surface. As discussed below with reference to <FIG>, however, the system <NUM> can be switched from a conventional arrangement in <FIG> to an arrangement having a flow control device in other stages of drilling. The flow control device can include a rotating control device <NUM> capable of isolating the annulus <NUM> of the wellbore <NUM> around the drillstring <NUM> from the surface. The rotating control device <NUM> or other flow control may also allow for drilling fluid to be injected, pumped, and the like into the annulus <NUM> from the surface equipment. In other arrangements, a rotating control device <NUM> may not be used, and the wellbore <NUM> may be closed in other known ways. Further still, the wellbore <NUM> may not need to be closed in this manner with the flow control device <NUM> and may remain open to atmosphere at surface. Flow returns to the surface can be stopped using conventional techniques.

Finally, a programmable control device or control <NUM> is communicatively coupled to the drilling system <NUM> and to the instrumentation <NUM>. The control <NUM> can include manual and automated interfaces for conducing drilling operations as disclosed herein and can be implemented using know components, such as processing equipment, user interface, machine interfaces, etc..

As shown in the detail of <FIG>, the instrumentation <NUM> includes one or more pressure sensors <NUM>, one or more temperature sensors <NUM>, and one or more gas sensors <NUM>. These sensors <NUM>, <NUM>, and <NUM> can communicate with the control <NUM> of the drilling system <NUM> using known communication techniques, such as communication lines disposed along the casing <NUM> of the wellbore <NUM>. The pressure sensors <NUM> and the temperature sensors <NUM> can use quartz gauges typically used for downhole measurements. The gas sensors <NUM> can monitor for gas indicative of gas migration. These gases can include H2S, CO2, and other hazardous gases. The sensors <NUM> can be downhole fluid chromatography sensors or any suitable sensors.

As shown, the instrumentation <NUM> of the drilling system <NUM> can include a downhole valve <NUM> (e.g., casing valve or retrievable valve) disposed on/in the casing <NUM> of the cased section of the wellbore <NUM>. The sensors <NUM>, <NUM>, <NUM> can be part of such a downhole valve <NUM>. Briefly, the downhole valve <NUM> includes an isolation valve <NUM>, such as a flapper valve, that can be closed in a number of ways to close off the wellbore <NUM> below the valve <NUM>. For example, the isolation valve <NUM> may be opened/closed using hydraulics communicated with control line(s) or umbilicals from surface. In other ways, the valve <NUM> may be opened/closed without an umbilical and may instead be operated using telemetry or using Radio Frequency Identification tags and a receiver.

Although the instrumentation <NUM> is shown at one location/depth in the wellbore <NUM> and incorporated as part of a downhole valve <NUM>, the drilling system <NUM> can include instrumentation at multiple locations/depths in the wellbore <NUM>. Any of these multiple locations may include any one or more of the sensors <NUM>, <NUM>, <NUM> associated with the instrumentation <NUM> for providing different measurement points along the wellbore <NUM>.

In this initial stage of the drilling process of <FIG>, the drilling system <NUM> pumps drilling fluid <NUM> down the drillstring <NUM> and receives returns <NUM> that flow up the annulus <NUM> to the surface. This conventional drilling can be continued in the formation as long as possible and at least until a total loss or theft zone is expected or encountered. Such a theft zone may be associated with a reservoir having extensive fractures/vugs. As noted herein, a total loss or theft zone constitutes a zone of high porosity where lost circulation occurs. A considerable amount of the drilling fluid <NUM> pumped down the drilling string <NUM> would be lost to the theft zone, reducing the returns <NUM> to the surface. This could then make well control more difficult.

When a theft zone is expected or encountered, operations proceed to a process of closed hole circulation drilling with continuous downhole monitoring of the present disclosure. To that end, <FIG> illustrates the wellbore <NUM> being drilled in a second stage of the disclosed process, while <FIG> illustrates the wellbore <NUM> being drilled in a third stage of the disclosed process should the process fail to maintain the steps in the first stage. <FIG> illustrates the process <NUM> of closed hole circulation drilling with continuous downhole monitoring of the present disclosure.

During the process <NUM>, the drilling system <NUM> detects losses during the conventional drilling of the initial stage in <FIG> (Block <NUM>). As is customary, not all losses may be of particular concern and may be handled by the current drilling technique. Therefore, a comparison is made to determine if the static loss rate is at least within some limit of the current drilling rate (Decision <NUM>). For example, the static loss rate may be monitored and handled with conventional drilling techniques until the static loss rate reaches within a limit of about <NUM>% (i.e., half) of the current drilling rate. The value of the limit may depend on the drilling system <NUM>, the formation being drilled, and other factors consistent with a given implementation.

If the static loss rate has not reached the limit (No at Decision <NUM>), then the current regime for the conventional drilling of the wellbore <NUM> may be reviewed to provide better well control. For example, the control <NUM> may continue with the conventional drilling of the wellbore <NUM> with the system <NUM> in <FIG>, but the drilling may be modified using conventional adjustments, such as introducing lost circulation material (LCM) into the wellbore <NUM>.

Knowledge of the formation may indicate when theft zones may be encountered during drilling, and the process <NUM> can be converted before. In any event, if the static loss rate is at least within the limit (e.g., <NUM>%) of the drilling rate (Yes at Decision <NUM>), then the control <NUM> evaluates the reasons for the losses. For example, operations may determine that a total loss or theft zone having natural fractures may have been encountered during the conventional drilling of the formation so that mud cap drilling needs to be implemented.

The theft zone when drilling conventionally can cause undesirable excessive or total loss of circulation, differentially stuck pipe, and resulting well control issues. Switching to mud cap drilling as shown in <FIG> allows the drilling system <NUM> to take advantage of the presence of the theft zone <NUM>. Because the theft zone <NUM> is of high porosity and is relatively depleted, the theft zone <NUM> offers an ideal depository for clear, non-invasive fluids and cuttings during drilling. To that end, the process <NUM> commences with pressurized mud cap drilling (PMCD) to achieve pressure management of the wellbore <NUM> using a mud cap and pump rates.

At this point, the process <NUM> initiates a pressurized mud cap drilling regime (Block <NUM>). As shown in <FIG>, operations fill the wellbore <NUM> with a light oil-based fluid and water to fill the open hole <NUM> and the annulus <NUM> to commence with drilling. As a result, a mud cap <NUM> is placed in the annulus <NUM> surrounding the drillstring <NUM> to cap off returns in the open hole <NUM> from flowing upwards through the annulus <NUM>. To do this, a viscous fluid, such as a light annular fluid, can be pumped at a rate that overcomes gas/fluid migration rate down the annulus <NUM> at just below reservoir pressure to maintain the hole filled and to prevent annular gas migration from the theft zone <NUM>.

A surface (ball) valve (not shown) can be used at surface before pipe connections to isolate the new pipe stand, and the float valve <NUM> can prevent fluid from the wellbore from entering the drillstring <NUM> during pipe connections. A flow control device <NUM> can be installed in the drilling system <NUM> to isolate the annulus <NUM> of the wellbore <NUM> from the surface. In the pressurized mud cap drilling regime of <FIG>, the annulus <NUM> can be closed, for example, by a rotating control device <NUM>. As is customary, a flow spool or other component below the rotating control device <NUM> may allow for introduction of the mud cap <NUM>.

Either way, no returns are brought to surface during the pressurized mud cap drilling. Instead, a sacrificial or disposable drilling fluid <NUM> (e.g., water) is pumped down the drillstring <NUM>. An interface in the annulus <NUM> is maintained between crude oil, the sacrificial fluid <NUM>, and the annular fluid of the mud cap <NUM>, and the sacrificial fluid <NUM> and cuttings are lost to the formation fractures <NUM> in the theft zone <NUM>. The resulting annular backpressure is used to balance the reservoir pressure and maintain system balance.

As noted above, the mud cap <NUM> is used to increase the bottomhole pressure by forming a column of heavier and often viscosified mud in the annulus <NUM> of the wellbore <NUM>. The column is shorter than the total vertical depth (TVD) of the annulus <NUM>, and the size of the mud cap <NUM> is based on how long the mud cap <NUM> needs to be, the mud weight of the fluid in the mud cap <NUM>, and the amount of extra pressure that is needed to balance or control the well.

The weight for the light annular mud in the mud cap <NUM> is selected so that it is lower than the pressure gradient of the theft zone <NUM>. This helps avoid further loss of circulation. Some other factors of concern include the resistance of the mud in the mud cap <NUM> to contamination in the wellbore <NUM>, the mud's viscosity, and the mud's resistance to being broken up by flow or circulation.

Any gas migration into the mud cap <NUM> in the annulus <NUM> can be countered by bullheading the wellbore <NUM>. Bullheading involves forcibly pumping the fluids in the wellbore <NUM> into the formation. This may be done by pumping into the annulus <NUM> from the surface. Typically, the volume, the time interval, and the rate for bullheading are calculated based on current conditions.

In keeping the annulus <NUM> filled with the mud cap <NUM>, a decision is made in the process <NUM> to determine if the wellbore <NUM> can be kept full (Decision <NUM>). If the wellbore <NUM> can be kept full with the mud cap <NUM>, then operations perform an injectivity test and continue with the mud cap drilling technique, such as Closed Hole Circulation Drilling (CHCD) or Pressurized Mud Cap Drilling (PMCD) (Block <NUM>).

The injectivity test involves evaluating losses before making any decision to switch to PMCD/CHCD operation. Briefly, for example, a BOP (not shown) is closed, and the RCD flowline valve is closed for operations to proceed with performing the injectivity test. Operations stop annular fluid injection and determine the initial casing pressure (e.g., <NUM> kPa (<NUM> psi)) from stroke counters or another source. For the test, sacrificial fluid (e.g., seawater) is lined up to the surface pumps, and operations begin injecting the sacrificial fluid down the drillstring <NUM>. The pumping starts at a beginning rate for a period of time (e.g., start at <NUM><NUM>/hr (100gpm) for <NUM> minutes). The pumping rate is then increased in increments and held for a period at each increment until reaching a maximum drilling rate. For example, the pumping rate can be brought up in <NUM><NUM>/hr (<NUM> gpm) increments until reaching <NUM><NUM>/hr (<NUM> gpm), which may be the maximum drilling rate as per the drilling program. The increase at each increment can be held for <NUM> minutes.

In the meantime, the Stand Pipe Pressure (SPP) and the annular pressure are monitored. If the injectivity test indicates the annular pressure is below a given threshold (e.g., < <NUM>,<NUM> kPa (<NUM> psi)), the operations switch drilling to the PMCD mode. By contrast, if the annular pressure exceeds the threshold (e.g., > <NUM>,<NUM> kPa (<NUM> psi)), operations resume circulating with conventional drilling fluid and drill ahead, while monitoring losses. The switch to PMCD would then be made once a fracture system is encountered in the wellbore <NUM> that can handle the injection rate.

Operations continue with the control <NUM> managing the annular pressure in the wellbore <NUM> using the pressurized mud cap drilling techniques. As drilling continues, losses may be continually evaluated, and an assessment can be made of maintaining the annulus filled (Block <NUM>).

If the wellbore <NUM> cannot be kept full (No at Decision <NUM>), then operations switch to using continuous downhole monitoring according to the present disclosure rather than proceeding the pressurized mud cap drilling (Block <NUM>). In particular, for the pressurized mud cap drilling regime to proceed, pressure from the mud cap <NUM> may be measured at the rotating control device <NUM> while pumping the sacrificial fluid <NUM> so the annular backpressure can be maintained on the formation. For example, a reading of annular pressure at the rotating control device <NUM> may indicate that the wellbore <NUM> is being kept full with the mud cap <NUM>. As noted previously, the drilling system <NUM> may not include such a flow control device or a rotating control device <NUM>, and the wellbore <NUM> may be closed in other known ways.

Further still, the wellbore <NUM> may not need to be closed in this manner with the flow control device <NUM> and may remain open to atmosphere at surface. Either way, flow returns are not brought to the surface.

If the level of the mud cap <NUM> cannot be maintained up to the rotating control device <NUM>, then the pressurized mud cap drilling cannot be sustained. There may be several reasons when the wellbore <NUM> cannot be kept full. For example, the pump rates for pumping the sacrificial fluid <NUM> required to sustain the fluid level in the annulus <NUM> may exceed desired rates that can damage the mud pumps or cause other issues. In fact, the theft zone <NUM> may have a formation pressure that is below conventionally acceptable levels because the reservoir is in its depletion stage. For this reason, the wellbore <NUM> may not be kept full with even the lightest available fluid at the rig site.

At this point, operations stop pumping the fluid, let the fluid level in the wellbore <NUM> drop, and closely monitor the pressure in the annulus <NUM>. In the monitoring, downhole monitoring of the mud cap <NUM> is provided by the instrumentation <NUM> (e.g., the downhole valve <NUM> having the sensors <NUM>, <NUM>, <NUM>). Other forms of instrumentation <NUM> available in the art could be used. At the beginning when pumping is stopped, the monitored pressure at the instrumentation <NUM> is expected to decrease at a high rate until it is stabilized (+/-<NUM> kPa (100psi)) when the wellbore <NUM> is balanced with the reservoir pressure.

As shown in <FIG>, the wellbore <NUM> cannot be kept full so that the level of the mud cap <NUM> has receded in the annulus <NUM>. As noted herein, the wellbore <NUM> may not be kept full because the theft zone <NUM> encountered may have a pressure gradient with formation fluid far below <NUM>, <NUM>/m<NUM> (<NUM>-ppg). For example, the theft zone <NUM> may have formation fluid with a weight of <NUM>/m<NUM> (<NUM>-ppg), and the lowest available mud weight for the mud cap <NUM> will likely be higher, such as <NUM>/m<NUM> (<NUM>-ppg). Consequently, the level of the mud cap <NUM> has dropped, resulting in the decrease in monitored pressure at the instrumentation <NUM>. Eventually, balance is reach when the wellbore pressure <NUM> is balanced with the reservoir pressure.

At this point in the process <NUM>, an initial fluid level (IFL) is defined in the annulus <NUM> based on the monitored pressure and the fluid in the wellbore <NUM> (Block <NUM>). As described herein, the initial fluid level (IFL) can constitute a liquid/gas interface level or an elevation of the mud cap <NUM> used for managing and controlling the formation pressures.

As noted herein, the instrumentation <NUM>, such as in the downhole valve <NUM>, has the one or more pressure sensors <NUM> for measuring pressure in the annulus <NUM>. The light annular mud used in the mud cap <NUM> with its known mud weight fills a column in the annulus <NUM> and produces a calculable pressure at the location of the downhole valve's pressure sensor <NUM>. In this way, the initial fluid level (IFL) of the mud cap <NUM> in the annulus <NUM> can be determined based on the measured pressure from the known mud filling a calculable column of the annulus <NUM>.

At this point with the initial fluid level defined, operations proceed with the Closed Hole Circulation Drilling (CHCD) technique combined with continuous downhole monitoring (Block <NUM>). As before, fluid returns are not brought up the annulus to surface. The wellbore <NUM> can remain closed with the rotating control device <NUM> (if used) so gasses can be diverted from the rig of the drilling system <NUM>. As noted above, the rotating control device <NUM> can be used so that the rotating control device <NUM> also creates a closed system, making it easier to control the well. In other arrangements, the rotating control device <NUM> may not be used, and the wellbore <NUM> is closed in other known ways or may remain open to the atmosphere at surface.

Either way, with the mud cap <NUM> at the initial fluid level (IFL), operations start drilling by pumping scarification fluid <NUM> and monitoring the pressure at the instrumentation <NUM>. The monitored pressure indicates the initial fluid level (IFL) in the annulus <NUM> and the corresponding pressure that the mud cap <NUM> applies to the formation.

An emulsification <NUM> may develop at the interface between the sacrificial fluid <NUM>, the formation fluid, and the annular mud cap <NUM>. The emulsification <NUM> can initially keep formation gas <NUM> from migrating into the mud cap <NUM>. As will be appreciated, significant migration of formation gas <NUM> in the mud cap <NUM> would alter the density of the mud cap <NUM>, change the initial fluid level, and undermine the well control provided. As noted below, bullheading the wellbore can be used to counter the gas migration. Because the drilling system <NUM> can perform continuous operational monitoring and diagnostics, any bullheading of the wellbore <NUM> is based on the actual behavior of the downhole conditions, rather than just blind bullheading based on the predicted/assumed variables.

Therefore, in addition to monitoring pressure in the annulus <NUM> to define the initial fluid level of the mud cap <NUM>, temperature in the annulus <NUM> and H2S/CO2 gas values can be monitored closely at the downhole instrumentation <NUM> as additional indicators to detect gas migration. Temperature measured at the instrumentation <NUM> can detect an influx migrating in the mud cap <NUM> as the influx reaches the instrumentation <NUM> because the temperature of the influx will be higher than temperature of the bullheaded mud cap <NUM>. This can give an indication of gas migrating from the formation up through the mud cap <NUM>. The gas sensors <NUM> at the instrumentation <NUM> can also measure levels of gasses, such as H2S and CO2, as an indication of possible gas migration up the mud cap <NUM>.

With the initial fluid level defined, drilling of the wellbore <NUM> continues while the drilling system <NUM> pumps the sacrificial fluid <NUM> and the control <NUM> monitors for a change in the initial fluid level (Decision <NUM>). If the pressure measured at the instrumentation <NUM> shows a stable trend (e.g., +/- <NUM> kPa (50psi)), then operations continue drilling (Block <NUM>). Therefore, by monitoring the pressure, the control <NUM> continues to monitor the initial fluid level to determine whether there is an increase or a decrease in the fluid level (Decision <NUM>). Should the initial fluid level remain the same +/- a threshold, e.g., <NUM>-ft. , then the control <NUM> keeps drilling (Block <NUM>) and continues monitoring.

However, the level of the mud cap <NUM> may increase from the Initial Fluid Level (IFL) (Increase at Decision <NUM>) due to a complete formation plug off, an influx/gas stream, or a reservoir pressure increase. This increase of the mud cap <NUM> from the Initial Fluid Level (IFL) may then decrease due to a partial plug-off of the formation. In general, should an increase be detected by the continuous monitoring, operators stop drilling, turn off the mud pumps <NUM>, and bullhead the well. These steps will be discussed below.

By contrast, the level of the mud cap <NUM> may decrease from the Initial Fluid Level (IFL) (Decrease at Decision <NUM>) due to an encounter with another fracture/vugs or due to influx/gas streams. The decrease from the Initial Fluid Level (IFL) may then start to increase due the well flowing. In general, should a decrease be detected by the continuous monitoring, operations stop drilling, turn off the mud pumps <NUM>, and assess the situation. These steps will also be discussed below.

As disclosed herein, drilling through a relatively depleted and fractured/vugular reservoir can be achieved while continuously monitoring the fluid level of the mud cap <NUM> in the annulus <NUM> with the downhole instrumentation <NUM> (i.e., one or more downhole sensors or gauges <NUM>, <NUM>, <NUM> installed in the downhole valve <NUM>). For the monitoring, downhole sensors <NUM>, <NUM>, <NUM> measure pressure, temperature, gas level, and other variables if needed. Based on the downhole pressure readings, the fluid level of the mud cap <NUM> is identified using the control <NUM>, which includes a surface processing unit/software program. This allows the mud cap <NUM> to be constantly monitored to determine changes in its fluid level and to assess the behavior of the well.

For the increase in the level of the mud cap <NUM> from the Initial Fluid Level (IFL) (Increase at Decision <NUM>), the pressure measured at the downhole instrumentation <NUM> shows an increasing trend in pressure so that operations stop drilling and turn the pumps <NUM> off (Block <NUM>). Operations then assess the reasons for the increasing pressure. In particular, if the pressure stops increasing at least within a given time frame (Yes at Decision <NUM>) and subsequently keeps decreasing until a point above the initial fluid level (Yes at Decision <NUM>), the fracture <NUM> in the formation may have become plugged to some degree but not completely by the cuttings. In this case, operations re-evaluate a new initial fluid level (IFL) for the mud cap <NUM> in the wellbore <NUM> (Block 165A) so operations can continue drilling with the continuous monitoring regime under this re-evaluated initial fluid level (Block <NUM>).

If the pressure stops increasing (Yes at Decision <NUM>) without then decreasing (No at Decision <NUM>), the fracture <NUM> may be plugged significantly, and the wellbore <NUM> sees the increase in fluid level. Operations can then assess the well condition and may switch back to conventional drilling techniques, to pressurized mud cap drilling, or to resuming the drilling with the continuous monitoring regime (Block 165B).

If the increasing pressure does not stop increasing at least within a given time frame (No at Decision <NUM>), then additional assessment is necessary. If the pressure continues increasing at a high rate, then a large influx from the formation <NUM> may be expanding in the wellbore <NUM>, thereby pushing up the level of the mud cap <NUM> and increasing the pressure reading at the instrumentation <NUM>. In addition to the high rate of pressure increase, the instrumentation <NUM> may measure the temperature potentially increasing and/or the H2S/CO2 levels potentially going up due to gas migration in the mud cap <NUM>. In this case, operations bullhead down the wellbore to pump out the fluids from the wellbore <NUM> into the formation and replace a mud cap <NUM> with new fluid (Block <NUM>) and re-evaluation the fluid level to be used (Block <NUM>). Even if the pressure continues increasing at a slow rate (and/or temperature increases and/or the H2S/CO2 levels go up), a gas stream may be pushing the mud level up. The wellbore may need to be bullheaded (Block <NUM>), and the fluid level may need to be reevaluated (Block <NUM>).

If the influx is due to encountering a higher reservoir pressure than encountered at the previous fracture zone <NUM>, then the initial fluid level (IFL) needs to be re-evaluated based on the new reservoir pressure (Block <NUM>) so operations can continue drilling with the continuous monitoring regime under this re-evaluated initial fluid level (Block <NUM>).

By contrast, for the decrease in level of the mud cap <NUM> from the Initial Fluid Level (IFL) (Decrease at Decision <NUM>), the pressure at the instrumentation <NUM> may show a decreasing trend so that operations stop drilling and turn the pumps <NUM> off. Operations then assess the reasons for the decreasing pressure.

The pressure would not be expected to simply continue decreasing. The pressure decrease is expected to stop at some point when a balance is achieved with the reservoir pressure. If the pressure decreases, stops at some point, and then increases, the wellbore has possibly encountered another fractured theft zone. For example, the fractured theft zone may produce a kick or influx due to the loss of the mud cap's hydrostatic head. In this case, operations bullhead the wellbore and re-evaluate the initial fluid level for the mud cap <NUM> (Block <NUM>).

On the other hand, if the pressure stops decreasing at some point and then increases (and/or temperature increases and/or H2S/CO2 levels go up), then the wellbore may be flowing. In this case, the wellbore needs to be bullheaded, and the IFL needs to be re-evaluated with the new well condition (Block <NUM>).

Throughout the drilling process <NUM>, drilling to a given depth can be completed. A new liner can then be run downhole of the existing casing <NUM> and cemented in the open hole <NUM> to isolate the previously drilled zones of the formation. Such a liner can include additional downhole instrumentation <NUM> according to the present disclosure, and/or any existing instrumentation <NUM> on/in the previous section of casing <NUM> can still be used for monitoring the next hole sections. Also, a retrievable downhole valve <NUM> with the instrumentation <NUM> can be used on top of the new liner.

Once the recently drilled zones are isolated, deeper zones can then be drilled into the formation according to the techniques of the present disclosure as needed. This process can be repeated as needed until a total depth of the wellbore <NUM> is reached in the reservoir. Completion operations known in the art can then be performed to prepare the wellbore for production of the hydrocarbons from the reservoir.

Monitoring for gas migration may be difficult if oil-based mud (OBM) is used for the mud cap <NUM>. Therefore, closing the flapper valve <NUM> of the downhole valve <NUM> may be performed from time to time to monitor gas migration behavior in the oil-based mud. This step can be included as a part of the procedures during drilling in the continuous monitor mode (Block <NUM>) when the mud cap <NUM> has oil-based mud.

To close the flapper valve <NUM>, the bottom hole assembly is <NUM> is positioned above the downhole valve <NUM>, which is then closed by the control <NUM> using umbilical (hydraulics) or non-umbilical (e.g., RFID). Pressure can be bled off above the closed flapper valve <NUM>, and the wellbore can be monitored to confirm isolation. The instrumentation <NUM> can then make measurements to detect gas migration using the pressure sensor <NUM>.

For example, the pressure sensor <NUM> can monitor for an increase in the pressure downhole of the flapper <NUM> over time until it stabilizes and can estimate a rate of gas migration based on distance between the downhole valve <NUM> and a loss zone. For example, the pressure at downhole valve <NUM> may be <NUM> MPa (<NUM> psi) when the flapper valve <NUM> is initially closed. The pressure may start increasing until it stabilizes at some level (e.g., <NUM> MPa (<NUM> psi)). This increase until stabilization would have taken a given amount of time, such as <NUM>. In this example, the gas migration rate can be estimated to be about <NUM> kPa/min (<NUM> psi/min). Alternatively, it can be assumed that the gas will migrate from the first loss zone to the depth of the control valve <NUM>, and the distance can be used for a rate estimation. For instance, the distance from the first loss zone in the wellbore <NUM> to the downhole valve <NUM> may be <NUM> (<NUM> ft), and it may have taken <NUM> for the monitored pressure at the downhole valve <NUM> to be stabilized. In this case, the migration rate can be estimated to be <NUM>/min (<NUM> ft/min). Or, if gas is already between valves <NUM>, the estimation can use that distance.

This procedure of closing the flapper valve <NUM> might not be feasible as it requires pulling a few stands of the drillstring <NUM> out of hole so the valve <NUM> can be closed to check for gas migration. However, closing the flapper valve <NUM> can be done once to assess gas migration behavior of the reservoir with either water-based mud (WBM) or oil-based mud (OBM). This assessed behavior would then help to calculate bullheading volume, bullheading time interval, and bullheading rate based on the actual gas migration rate, not based on a predicted rate from simulation software.

As will be appreciated, teachings of the present disclosure, such as the operational decisions and process steps disclosed above, can be implemented by the control <NUM> of the drilling system <NUM> in digital electronic circuitry, computer hardware, computer firmware, computer software, or any combination thereof. Teachings of the present disclosure can be implemented in a programmable storage device (computer program product tangibly embodied in a machine-readable storage device) for execution by a programmable control device or processor (e.g., of the control <NUM>) so that the programmable processor executing program instructions can perform functions of the present disclosure. The teachings of the present disclosure can be implemented advantageously in one or more computer programs that are executable on a programmable system, such as the control <NUM> of the drilling system <NUM>, including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system, at least one input device, and at least one output device. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, including by way of example semiconductor memory devices, such as EPROM, EEPROM, and flash memory devices; magnetic disks such as internal hard disks and removable disks; magneto-optical disks; and CD-ROM disks. Any of the foregoing can be supplemented by, or incorporated in, ASICs (application-specific integrated circuits).

Claim 1:
A method of drilling a wellbore (<NUM>) in a formation of a reservoir, the method comprising:
providing instrumentation (<NUM>) associated with casing (<NUM>) disposed in the wellbore (<NUM>);
drilling, in a first stage, an open hole section (<NUM>) of the wellbore in the formation for an extent beyond the casing (<NUM>) by pumping drilling fluid at a drilling rate through a drillstring (<NUM>) and allowing returns of the drilling fluid to surface through an annulus (<NUM>) between the wellbore (<NUM>) and the drillstring (<NUM>);
detecting (<NUM>, <NUM>), during the first stage of drilling, that a static loss rate of the drilling fluid to the formation reaches within a loss circulation limit of the drilling rate;
in response to the detection (<NUM>, <NUM>), (a) filling (<NUM>) the annulus (<NUM>) of the wellbore (<NUM>) with a mud cap (<NUM>) of annulus fluid up to a flow control device (<NUM>), (b) determining (<NUM>) that the annulus (<NUM>) cannot be kept filled with the annulus fluid up to the flow control device (<NUM>), (c) allowing the annulus fluid in the annulus (<NUM>) to balance with reservoir pressure, and (d) defining (<NUM>) an initial fluid level (IFL), below the flow control device (<NUM>) where the mud cap (<NUM>) in the annulus (<NUM>) is balanced with the reservoir pressure, by monitoring pressure in the annulus (<NUM>) using the instrumentation (<NUM>);
drilling, in a second stage, the open hole section (<NUM>) of the wellbore (<NUM>) in the formation for a subsequent extent beyond the casing (<NUM>) while the annulus (<NUM>) is filled with the mud cap (<NUM>) to the initial fluid level (IFL) by: pumping (<NUM>) a sacrificial fluid (<NUM>) through the drillstring (<NUM>) without returns to surface through the annulus (<NUM>), and monitoring the mud cap (<NUM>) in the annulus (<NUM>) by monitoring pressure using the instrumentation (<NUM>) to detect (<NUM>) a change relative to the initial fluid level (IFL); and
controlling (<NUM>, <NUM>, <NUM>) the drilling in response to the detected change (<NUM>).