Combination of PMCD, downhole valve minimizes sour gas at surface
Dealing with extreme kick/loss cycles is a given in the vuggy, fractured limestone of East Java’s Kujung formation. The difficult drilling is further complicated by reservoir gas with hydrogen sulfide (H2S) concentrations up to 7,000 ppm and between 20% to 25% carbon dioxide (CO2), all of which is compounded by a high population density in the areas surrounding the well sites.
To minimize the release of sour gas at the surface and to drill the hole into the target zone without damaging production potential, the operator used pressurized mud cap drilling (PMCD) in conjunction with a downhole isolation valve (DIV).
Use of the managed pressure drilling (MPD) methodology with surface-controlled valve technology has improved safety by greatly minimizing the amount of gas and fluid reaching the surface. Kick/loss cycles have been effectively managed, which allowed drilling to reach target depth with minimal formation skin damage. Recent MPD drilling operations have resulted in an absolute open flow potential relatively higher than previous, non-MPD wells and a significantly lower skin effect.
Exploratory wells drilled previously and conventionally in the field experienced significant problems with well control events. Much of the drilling budget was spent on cement and lost-circulation material (LCM) in efforts to mitigate circulation losses and the resulting kicks.
One of the exploration wells reached TD in about 230 days versus the planned 80 days. The many problems encountered included poor rig performance, shale sloughing, stuck pipe and severe losses in drilling the Kujung formation.
The experience benefited the next exploratory well drilled. Planned for almost 100 days, it took only 62 days to reach TD. But the well was not without problems. When drilling the 12 ¼-in. hole section to the top of the Kujung, severe losses of 60 bbl/hr to 600 bbl/hr were experienced along with subsequent kicks. Bullheading and well control operations were performed continuously for more than 20 days, including 19 cement plugs, before drilling operations could continue.
In addition, tripping the drill pipe in these conditions required killing the well to maintain control, which increased formation skin damage and compromised potential gas production. The alternative of snubbing – which would have eliminated formation damage by allowing pipe to be tripped in an underbalanced wellbore – was considered but rejected because of expense, long trip times and safety risks.
To resolve these challenges, MPD techniques, which involve drilling at balance or with a very slight overbalanced pressure, were selected. The MPD equipment spread was designed to minimize if not eliminate the release of sour reservoir fluids at surface. Included in the design was a downhole isolation valve to increase safety by isolating the reservoir during tripping operations.
Drilling plans specified the use of conventional drilling methods until losses were encountered and then called for a gradual shift from a conventional to a nitrified fluid. A PMCD methodology would be implemented depending on the degree of circulation losses encountered.
The PMCD variant of MPD technology allows drilling to continue during severe or total fluid losses. It is an effective alternative to time-consuming, loss-kick-cure cycles that are problematic in conventional operations. The technique takes advantage of the natural ability of the fractured formation to accept the drilling fluid and drilled cuttings instead of trying to cure these losses.
PMCD typically uses a viscous, weighted mud cap in the annulus to hold the reservoir pressure in balance while simultaneously pumping sacrificial drilling fluid (normally water) down the drill pipe. There are no returns to surface because the sacrificial fluid and all cuttings are lost into the formation.
With PMCD, drilling operations are conducted conventionally until severe losses are encountered. The system does not interfere with conventional drilling equipment or procedures. PMCD differs from a conventional mud cap in that the annulus fluid column is weighted to deliver a hydrostatic pressure slightly below the reservoir pressure. This results in a slight annular backpressure that is held by a rotating control device (RCD) at the surface. The backpressure is monitored to record changes in reservoir pressure and detect annular gas migration. When a predetermined pressure value is reached, pressure is managed by adding fluid to the annulus.
Isolating the Hole
DIV technology is used to enhance safety while tripping wells drilled in underbalanced or managed pressure modes. It is a surface-controlled device made up as an integral part of the casing. With the same inside diameter as the casing, the full-bore device allows the passage of downhole tools when it is in the open position. It is basically a flapper valve with a metal-to-metal seal rated to a differential pressure of 5,000 psi and a temperature of 300° F.
The DIV is opened and closed by hydraulically moving an internal sleeve via two ¼-in. lines run in the casing annulus from a surface control unit. The hydraulic lines are clamped to the casing using cross-coupling clamps that protect the control line from abrasion.
The DIV has been used globally in more than 200 applications, where it has reduced operational costs and increased safety. The valve saves time by eliminating the need to circulate kill fluid into and out of the well while still protecting against potential swabbing and kicks while tripping.
Used with the PMCD technique, the DIV eliminates the need to kill the well before pulling the bottomhole assembly out of the hole – often a very lengthy, expensive and sometimes futile process when multiple trips are required in severe circulation loss conditions. In addition to tripping drill pipe, the DIV provides a means of safely and efficiently running and installing the completion assembly in a live well.
MPD DIV Combo
PMCD and DIV technologies have been successfully merged and implemented in onshore drilling operations in other parts of Indonesia. This East Java application extends the use to a more challenging setting involving a sour-gas reservoir.
The MPD equipment used in the field consists primarily of a simplified RCD surface equipment spread and the DIV. The RCD is positioned on top of the BOP stack together with the ancillary equipment required for the PMCD application. The RCD device closes the circulating system loop by sealing around the drill pipe and redirecting fluid and gas flow away from the rig floor, which allows drilling and tripping operations to continue while maintaining pressure on the well.
In contrast with a conventional circulating system that is open to the atmosphere, the closed-loop MPD system uses the incompressible drilling fluid in the wellbore to almost immediately convey downhole pressure fluctuations to the surface or, conversely, to change downhole pressure by applying backpressure to the annulus, without the need for manipulating mud weight.
In this application, the RCD was a passive type rated to 2,500 psi for dynamic conditions and 5,000 psi for static conditions. The RCD has connections for a 7 1/16-in. flow line, a 2 1/16-in. auxiliary line and a 13 5/8-in. bottom flange. Valves and pipework consist of a manually and hydraulically operated 7 1/16-in., 5,000-psi full-bore flow line plus two sets of 2 1/16-in. hydraulically operated valves for the trip tank and injection lines, along with pipework, elbows, connections and fittings that are attached to the RCD.
A 9 5/8-in., 47-ppf, 5,000-psi DIV was run as an integral part of the 9 5/8-in. intermediate casing string. With the valve closed and well pressure isolated below it, surface pressure is released and pipe is tripped in or out of the well at conventional speeds without swabbing effects on the lower open-hole interval. The need for pumping well control fluids is eliminated.
With the DIV closed, MPD equipment can be removed and BHAs changed even if the well is trying to flow. Once the BHA has been changed, it is tripped back into the hole to the depth of the DIV. The well is then closed at the surface using the RCD equipment, the DIV is opened, and tripping the BHA into the well continues. A similar procedure is performed when running the completion assembly.
The RCD, valves and pipework needed for PMCD were installed before drilling out of the 9 5/8-in. casing so that return fluids from the 8 ½-in. section could be contained and diverted. The system also provided a precaution in the event that losses were encountered drilling into the top of the Kujung formation.
To reduce the chance of losses, the well plan called for penetrating the top of the Kujung as little as possible before setting 7-in. casing. If losses were encountered when penetrating Kujung, the objective was to control them with LCM so that mud could be kept in the hole and the casing run.
Using water instead of mud was a last-resort contingency due to the possibility of an adverse reaction from the interbedded shale/limestone formations directly above the Kujung. In that event, MPD equipment provided the means to trip the BHA above the reactive formation before introducing water. In contrast, severe or total losses in the 6-in. production hole required only a shift from mud to water and changing to MPD for pressure management.
MPD with Casing Valve Operation in East Java
For the well recently drilled in the area, both the RCD and DIV were in place prior to drilling the reservoir section. The DIV was installed permanently as part of the 9 5/8-in. casing string at 1,901 m and 19˚ inclination. The overpressured thick shale above the subnormal, naturally fractured limestone was addressed with two casing sections. This change to the conventional well design improved drilling by resulting in a 6-in. open hole in the reservoir section.
The MPD operational outline for the well called for conventional drilling methods in the 6-in. hole until losses were encountered. A gradual shift from a conventional to a nitrified fluid was then planned, with a change to a PMCD system depending on the degree of circulation losses encountered.
Drilling the 6-in. section started and proceeded conventionally until partial and then total circulation losses were encountered. After pumping mud and water with no returns, gas was flowed through the separator and flared. However, the detection of sour gas at the surface prompted the cessation of drilling, and the well was shut in with surface pressure at 2,870 psi.
PMCD methods were implemented immediately once total losses were confirmed in the lower hole sections. This step eliminated the use of nitrified fluids, which had limitations in terms of equipment and LWD/MWD performance.
Well control and kill steps used annular pressure to force the sour fluids back into the reservoir. Fresh water was bullheaded into the annulus until the annular pressure was reduced to less than 200 psi. Drilling then continued using PMCD methods for approximately 100 additional meters.
To ensure that cuttings were being circulated into the loss zone, high-viscosity pills were pumped in the middle of each stand and before every connection. However, at target depth, the drillstring stuck in the hole. Data indicates that there were no significant increases in torque or casing and standpipe pressures, and during PMCD operations the cuttings were not plugging the fractures. However, it was determined that more detailed post-TD PMCD procedures were required, along with closer adherence to conventional hole-cleaning practices.
Attempts to free the string were unsuccessful, and ultimately the BHA was left in the hole. The subsequent fishing job, which involved numerous runs, was performed in PMCD mode and through the DIV. After each fishing run, the fishing assembly was pulled above the DIV and the valve closed, allowing the assembly to be tripped out of the hole without swabbing pressure. Once the tools were tripped out, the DIV was opened so that constant annular pumping could be used to keep the sour reservoir fluids in check.
When fishing efforts failed, a cement plug was set above the abandoned BHA. A drill stem test (DST) was then performed through the DIV. Once the DST operations were completed, the well was temporarily plugged and abandoned using the RCD and DIV equipment. Throughout these operations, the DIV was cycled 47 times, with much of that under pressure.
Recent drilling operations in East Java have shown the effectiveness of combining PMCD and DIV to drill difficult wells to TD and complete them while minimizing reservoir H2S and CO2 gas at the surface. In drilling the vugular, fractured limestone, the ability of PMCD to continue drilling despite severe and total fluid losses significantly improved safety and efficiency, reduced mitigation time and materials, and avoided formation skin damage.