The seamless combination of two managed-pressure drilling (MPD) techniques has resulted in the successful drilling of a statically underbalanced high-rate onshore gas well in southern Sumatra, Indonesia. The integrated MPD approach reduced formation damage and provided the means to continue drilling ahead despite total circulation losses.

Formation damage in the reservoir was reduced using the constant bottomhole pressure (CBHP) variant of MPD to enable drilling with a statically underbalanced freshwater fluid system. When severe circulation losses were encountered, freshwater drilling fluid was sacrificed to the formation in a simple transition to pressurized mud-cap drilling (PMCD) methods, which allowed drilling to continue without restoring circulation.

The application is the latest advancement in the use of MPD methods in South Sumatra. Total circulation losses and minimizing formation damage have long been the object of MPD innovations in the area.

MPD heritage

MPD applications in South Sumatra began more than a decade ago with PMCD methods to drill in total lost circulation conditions while monitoring and controlling wellbore influxes. While successful, the technique required killing the well prior to pulling out of the hole, which is time-consuming and can result in formation damage. Weatherford’s development of a downhole isolation valve (DIV) to isolate the wellbore eliminated the need for killing the well, reduced the risk of formation damage, and greatly improved the efficiency and effectiveness of the PMCD technique.

The most recent MPD applications in Sumatra add CBHP methods to this system to further reduce potential formation damage. This plan uses CBHP to drill with statically underbalanced fresh water, unlike previous applications where overbalanced drilling fluid was required, only to be lost and to impair the productivity of the reservoir once circulation losses occurred. In the current setup, with the automated MPD manifold and the CBHP option available, when total losses were encountered, drilling would be transitioned to PMCD and fresh water would be pumped down the drillpipe and the annulus to prevent any gas migration up the wellbore. Having the same fluid in CBHP and PMCD modes greatly simplifies the MPD operation, thereby making operational efficiency an added advantage of the setup in addition to mitigating formation damage.

Methods and technology

CBHP allows the formation to be drilled with the same bottomhole pressure while circulating and with pumps off. The technique also facilitates drilling in an overbalanced state with a drilling fluid density that is less than the formation pressure. PMCD allows drilling to continue in total loss conditions with a sacrificial fluid that is lost to the formation along with cuttings. Without the need to mitigate losses, formation damage and costs from lost circulation material (LCM) and cement are eliminated with PMCD. Both MPD techniques depend on a small set of equipment that includes a rotating control device (RCD), an automated MPD choke manifold, and a DIV.

The RCD creates the prerequisite closed-loop drilling system by containing and redirecting annular flow to an automated choke manifold. The model used for the Sumatra well has dual-barrier rotating sealing elements.

Downstream of the RCD, the automated MPD choke manifold monitors flow in and out of the wellbore and is used for applying surface backpressure to manipulate the bottomhole equivalent circulating density (ECD). The manifold model used is equipped with two 3-in. chokes, a Coriolis mass flowmeter, and precision quartz pressure sensors. It is automated by a real-time monitoring, analysis, and control system.

The DIV used in the MPD operations is a surface-controlled system run as an integral part of the casing string. Its purpose is to avoid the introduction of swabbing and surging pressures when the drillstring is pulled out or run in the hole.

In operation, the drillstring is tripped out until the bottomhole assembly (BHA) is above the valve. The valve is then closed. Pressure above the valve is bled off, and the drillstring can be safely removed. The drillstring is tripped back into the well until the BHA is above the valve, at which point the valve is reopened and the operation continues.

CBHP technique

When drilling a well using CBHP, achieving an overbalanced condition requires application of backpressure. Backpressure enables a drilling fluid that is lighter than the formation pressure to function in an overbalanced state.

There are limits to how much pressure can be applied. The first limit is defined by the RCD pressure rating. The second limit is defined by the leak-off test (LOT) pressure. The total ECD at the shoe, which includes the SBP, must be lower than the LOT pressure.

Backpressure is managed through the MPD choke manifold by setting the desired SBP value. The MPD control system calculates the difference between the set value and the real value sensed by pressure sensors in the manifold and commands choke adjustments accordingly.

When a pipe connection is made and there is no circulation through the drillstring, SBP is applied using an auxiliary pump that circulates drilling fluid directly to the annulus and back to the choke manifold.

CBHP drilling was conducted successfully in the section using SBP to create pressure sufficient to balance the formation pressure.

PMCD technique

As the drilling assembly reached deeper into the formation, natural fractures were encountered, and losses began to occur. The resulting decrease in the rate of returns initiated a choke response to compensate for the annular pressure drop.

Total loss conditions occurred and, with the choke fully closed, additional water was injected into the annulus to offset the lack of returns from the well. This shift produced a seamless transition from CBHP operations to PMCD.

In PMCD mode, three mud pumps were used to deliver the water volume needed to maintain an annulus pressure sufficient to balance the formation pressure. Two pumps provided a 1,893-l/min (500-gal/min) rate down the drillstring, and one pump delivered 757 l/min (200 gal/min) down the annulus. With data from pressure sensors on the RCD and at the standpipe manifold, it was possible to determine a likely cause of what was occurring downhole based on changes in annulus and standpipe pressures. While drilling continued, the injection rate was increased to bullhead the migrated gas out of the annulus. Success was indicated by an annular pressure drop.

The DIV made the tripping operations (in and out) more efficient, allowing tripping to continue with the certainty that any gas or fluid influx was trapped under the downhole valve.

Drilling complex wells

The successful application and integration of the two MPD techniques to drill the Sumatran well illustrates a growing ability to address complex well issues. The production impairment potential from drilling-related formation damage in the high-rate gas well, along with the likelihood of total circulation losses drilling the production interval, presented significant challenges.

These difficulties could have terminated the drilling short of total depth or limited the well’s production rate. Instead, CBHP and PMCD techniques used in conjunction with a DIV provided a single MPD solution that mitigated both challenges.

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