IADC/SPE 128923

New Automated Control System Manages Pressure and Return Flow While Drilling and Cementing Casing in Depleted Onshore Field Julio Montilva, Shell Exploration & Production Company; Paul Fredericks and Ossama Sehsah, At Balance

Copyright 2010, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2010 IADC/SPE Drilling Conference and Exhibition held in New Orleans, Louisiana, USA, 2–4 February 2010. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.

Abstract Development efforts by Shell in South Texas have focused on technology solutions to eliminate the often encountered troubles drilling through significantly depleted sands to get to over pressured reservoirs below. The limits imposed by those conflicting conditions create narrow windows in which the difference between equivalent circulating density (ECD) and static bottom hole pressure (BHP) can be the difference between lost circulation and influx.

Liner drilling with statically underbalance (SUB) mud is one solution Shell uses in low permeability reservoirs to eliminate lost circulation in part because it eliminates swab and surge effects and heavy trip margins. But by itself that solution doesn’t work everywhere. In the McAllen and Pharr fields the amount by which the risk of losses can be reduced with liner drilling is limited because the sands can be more permeable and more likely to flow with SUB mud. For that reason Shell turned to automated managed pressure drilling (MPD) as a solution to drill more permeable reservoirs with SUB mud without influx.

For the past two years Shell has used those complementary solutions in the McAllen-Pharr fields to improve drilling efficiency and reduce costs with mud statically less than pore pressure and constant bottom hole pressure (BHP). Recently, Shell drilled the Bales #7 well in the McAllen Field Wide Unit using a new scaled-down automated MPD system. The lower 700 feet of the 6 ½” hole was drilled in with 3 ½” production tubing with 15.7 ppg static mud into a target sand with an expected pore pressure of 15.8 ppg. In that interval the ECD was 16.2 ppg and the fracture gradient was 16.5 ppg which was the narrowest window that Shell has drilled in the McAllen-Pharr area to date.

During casing drilling operations there was a steady flow of drill gas that varied between 1100 and 1400 units. Even with the drill gas the MPD system managed the BHP at a 16.2 ppg set point, +/- 0.18 ppg, without the use of an automated back pressure pump. That allowed Shell to avoid losses and the cost of a 5 ½” contingency liner drilling operation. In addition, and in the first of its kind application, Shell used the system to manage the BHP while cementing the drilled-in production tubing.

With its smaller footprint, more efficient automated control, and proven ability to manage constant BHP this new MPD system can provide onshore and offshore operators a solution to improve drilling and cementing operations in mature depleted fields.

Introduction The McAllen and Pharr fields are located in Hidalgo County which is situated in South Texas along the Rio Grande River (Fig. 1). Shell acquired those fields in 2006 nearly 70 years after they were first discovered during which time nearly 1.4 TCF of gas has been produced from reservoirs in the Frio formations. Initial production was from shallow zones, many of which are now depleted by as much as 5,000 psi below their original pressure. The fields’ extended history of production from multiple, comingled zones and their complex patterns of hard -to-map faults made it difficult for Shell to predict pore pressure and depletion. Isolating the severely depleted zones with liners is impractical because they are often found between over-pressured virgin sands.

Compared to Shell’s other nearby fields in the Vicksburg formations those in the Frio formations have substantially higher permeability and require heavier mud weight to avoid influx. A limiting factor in the McAllen-Pharr field is the ease with

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which losses occur in many of the reservoir sands due to the depletion induced lower minimum horizontal stress. The resulting narrow pressure profile and the inaccurate pore pressure predictions have complicated Shell’s early drilling efforts with excessive lost circulation and well control events.

In one early example, a well was drilled to its 7 5/8” liner point with 13.5 ppg oil base mud and substantial amounts of background gas. Total losses occurred when the mud weight was raised to 14.7 ppg prior to tripping out of the hole. After pumping cement and reducing the mud weight to 12.0 ppg the liner had to be drilled-in without returns then cemented in place. A subsequent well drilled through a different depletion profile using a 16.2 ppg mud suffered losses in the same way when the mud weight was raised to 16.4 ppg before tripping out. In that well it took few days to pump LCM, get control of the losses and gas, run open-hole logs and reduce the mud weight to 15.9 ppg to get ready to run the liner. However, during reaming operations the liner got differentially stuck off bottom and the well had to be shut in to circulate out gas. An isolation packer was finally run after squeezing cement. Both of those wells suffered losses at lower than anticipated mud weights and only after raising the mud weight to trip out of the hole.

To reduce those types of lost circulation events Shell first turned to liner drilling because it offered several benefits in that depleted environment. One benefit was eliminating the need to raise the mud weight for trips simply because there is no need to trip – eliminating trips eliminates swab and surge effects. Shell derived another more selective benefit from liner drilling in low permeability reservoirs. They took advantage of the fact that the low permeability reservoirs would not flow easily when the BHP was below pore pressure. That meant they could drill those zones with statically underbalanced mud (relative to pore pressure) and experience little or no risk of influx when the mud pumps were turned off. That gave Shell the ability to reduce the ECD and the risk of lost circulation in sands with low fracture gradients. And, it allowed Shell to eliminate the need for extra casing strings.

Both of the previously discussed wells would have benefited from liner drilling because both were drilled problem free to their liner points and only ran into trouble with lost circulation when the mud weight was raised to trip out of the hole.

However, Shell’s use of liner drilling was limited in the McAllen-Pharr field where there is a high level of uncertainty before drilling begins about the pressures and permeabilities they will encounter. Reservoirs sands with higher than expected permeability will deny them the advantage of static underbalance when the rig pumps were shut down. Early on Shell discovered that the permeability of some reservoir sands can be high enough to flow during connections when the mud is statically underbalanced and produce without being fractured. That limited the amount by which they could reduce the mud weight and the effectiveness of liner drilling.

In their interest to extend the benefits of drilling with casing Shell had to find a separate way to avoid losses in the shallow depleted sands while drilling with the higher ECD needed to avoid influx in the deeper permeable reservoirs. In fact, Shell had already found a way to manage similar problems in mature offshore fields and decided to use the same type of system in South Texas. It became a matter of adapting the technology to onshore conditions.

That was two years and 7 wells ago and what started out as a simple matter of technology migration evolved into a sustained effort of technology development. That effort culminated in a more efficiently designed system for automated pressure control which was used in the Bales #7 well to manage pressure while drilling and cementing.

System Description The automated MPD system that Shell was using in their deepwater Gulf of Mexico fields included a self-contained, skid mounted choke manifold and backpressure pump, a Coriolis flow meter, an automated pressure relief choke, and a separate control cabin (Fig. 2). A high pressure rotating control device was used to provide the drill pipe seal. The self-contained choke manifold though functionally suitable for land based MPD operations possesses features that are primarily meant to conform to offshore specifications. One of those features is the protective DNV certified crash frame makes the manifold cumbersome to handle. The typical self-contained offshore MPD manifold requires heavy lifting equipment for loading, unloading, and location placement which can be impractical for quick land based applications.

After the first well in the Pharr field, in the spring of 2007 Shell and At Balance started looking for ways to improve the system for land operations. They focused on ways to reduce the size and weight of the manifold, to make it easier to handle and transport and faster to rig-up. In reconstructing the manifold design At Balance reduced the number of chokes, valves, and bypass lines which also drove improvements in the hydraulic power system. Those were significant changes that led to a new manifold design that is modular in form and efficiently scaled.

The improvements that were being made to the manifold design were also accompanied by improvements to the operating program and pressure control processes. Reducing the amount of hardware in the manifold meant that the new operating system had to be written to preserve redundancy through functional efficiency – that is, it had to do more with less. One way it does that is in the way it manages the chokes. In its original design the choke manifold had three chokes, two of which

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were redundant for active backpressure management and one which was for active pressure relief (Fig. 3). However, in the new manifold there are only two (Fig. 4). Under the control of the new operating system one choke is always on line and dedicated for active backpressure management while the other is held in reserve as a backup to the primary choke in the event it becomes plugged. At the same time, the second choke is also used for automated pressure relief.

The pressure relief function uses a safety bias which is a prescribed amount by which the backpressure is allowed to increase above the set point before the system automatically opens the choke to relieve pressure. As the pressure is relieved the system automatically closes choke until the level returns to the set point at which point the system resumes normal control. Unlike a typical pressure relief valve which is a purely mechanical device that has only two states – open or closed – the position of an automated pressure relief choke is controlled to manage the pressure within the limits set by the safety bias. In addition, the smooth action of the choke protects the well against sudden spikes in backpressure above or below the ECD set point.

Another important aspect of this new Automated Pressure DrillingTM (APDTM) system is the way in which it can be expanded to provide additional services such as RCD diagnostic monitoring, dedicated pressure relief at the wellhead, multiple kick detection indicators, automated backpressure pump operation, closed loop pressure control with PWD, and remote operation.

The principle objective of the APD system is simple – maintain a constant BHP in the annulus at a specified set point in the well. Together, the programmable controller and the real-time hydraulics model to which it is linked took into account a number of drilling parameters including wellhead pressure, hole geometry, mud properties, and rig pump stroke rate to calculate and respond to changes in the ECD and static BHP. Adjustments are made to the choke downstream from the RCD to ensure that the appropriate amount of backpressure is always being applied to the annulus to keep the BHP in the specified margin.

In very narrow downhole pressure windows it is important to avoid the surges that can occur when a choke is fully closed rapidly and to avoid the loss of trapped pressure. One way to do that is to continuously circulate drilling fluid through the choke manifold when the rig pumps are off. That can be done with a dedicated, automated backpressure pump or with a manually operated rig pump.

For the Bales 7 well the APD system consisted of a modular choke manifold and a Coriolis flow meter (Fig. 5). A rig pump was used for additional flow as needed to boost the level of the trapped pressure. A principle benefit of the modular system’s small footprint and easy handling is in the amount of time it takes to rig-up. On the Bales 7 well the MPD crew rigged up the modular system in 7 hours which was 60% faster than the time it took to rig up the system on the previous job and 85% faster than the 2 day average it took to rig-up the offshore system on earlier McAllen-Pharr wells.

Operationally the APD system was used to control the ECD in two separate hole sections – one conventionally drilled with jointed pipe and one with casing. During connections the system held the BHP constant primarily by trapping backpressure even with large amounts of drill gas.

It is a standard operating procedure to tune the system to the existing drilling parameters then perform a number of simulated connections to provide the drilling crew with the necessary training and practice. In the Bales 7 well the tests were conducted using a 13.2 ppg static mud weight in the 7 5/8” casing before drilling out of the shoe with a 6 ½” bit. One of the lessons learned with the system during this well was that when tuned to manage pressure during drilling operations the chokes will close at a slower rate during connections compared to when they are tuned for connections only. To compensate modifications were made to the pressure trapping procedure during connections that allowed the system to maximize the amount of pressure that was trapped and minimize usage of the rig pump.

MPD During Conventional Drilling Operations The area in which the Bales 7 well was drilled is characterized by complex faulting and a lack of offset well data. That made it difficult to predict the pore pressure and fracture gradient in several of the older reservoir sands that Shell was going to drill in the 6 ½” production hole.

Operationally, the plan for the 6 ½” hole was to drill with jointed pipe from the 7 5/8” casing shoe (~8700 ft MD) down to 10360 ft MD (Fig. 6). The plan included a costly 5 ½” drill-in liner contingency if the well lost circulation in this hole section. The well was drilled along an S-shaped trajectory with a 19 degree tangent section out to a departure of about 2100 ft until just above the 7 5/8” casing shoe where it was dropped back to vertical (Fig. 7).

Drilling began with a mud weight of 13.2 ppg and almost immediately below the shoe the well drilled through a pair of sands in which the pore pressure was estimated to be 4 to 6 ppg. That created an over-balance condition near the shoe of 3250 to 4150 psi. At the end of the 6 ½” section the mud weight was raised to 14.0 ppg while the estimated pore pressure increased to almost 15 ppg. That meant that virtually the entire 6 ½” hole section was drilled statically underbalanced relative to pore

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pressure.

The location for the ECD set point for drilling operations was fixed at the 7 5/8” shoe which at the beginning of the section was 14.15 ppg and at the end had been increased to 14.9 ppg. On average, while drilling the 1660 ft of 6 ½” hole the APD system controlled the ECD at the set point within +/- 0.12 ppg by continuously managing the backpressure between 100 to 200 psi (Fig. 8).

Sixteen pump transitions were made in the 6 ½” hole section 15 of which were during conventional drill pipe connections and 1 during replacement of the RCD sealing element. During the pump transition before and after each connection the APD system controlled the BHP by trapping the backpressure as the pumps were turned off and on. Piping was installed in the circulation system to allow one of the rig pumps to inject mud into the annulus through the kill line as additional backpressure is needed for BHP control.

The set point for the BHP during connections was higher than the set point established for drilling. The reason for that was to control the connection gas while the rig pump was offline. On average during the transitions the APD system managed to control the BHP fluctuations within +/- 0.25 to +/- 0.3 ppg (Fig. 9).

While drilling the 6 ½” hole section a 20 bbl influx occurred when the sealing element in the RCD started to leak. The contingency plan was immediately put in to action. The flow was diverted through the secondary flow line, backpressure was applied using the APD system, the annular preventer was closed, and then the pressure below the RCD was bled off. Once it was confirmed that there was no pressure below the RCD the sealing element was changed out. After circulating out the influx the section was drilled to a total depth of 10360 ft MD where the bit penetrated the second depleted sand with no losses.

Upon reaching TD a wiper trip was made back to the 7 5/8” shoe, the drill pipe was laid down, and the 3 ½” casing drilling string was picked up to finish drilling the production section to final TD.

Shell accomplished its primary objective in the 6 ½” hole section with the APD system – drill through the two depleted sections and avoid losing returns in both. Accomplishing that objective allowed them to avoid the significant cost related to the contingency 5 ½” liner drilling operations that would have been required if they had experienced loss circulation in either zone.

MPD During Casing Drilling Operations Shell’s target sand was still 700 feet below the 6 ½” hole section and its pore pressure was expected to be at least 1.5 ppg greater than the maximum already drilled. That and the fact that the depletion levels were determined to be as low as expected meant that the risk of loses in the production section would be too great with a conventional assembly.

The objective for MPD in this final section was to minimize the ECD to avoid losses and mange the gas. As before in the 6 ½” hole section the APD system was used to manage the ECD while drilling the well and hold it constant during connections. One of the rig pumps was hooked up to the kill line to help manage the BHP and preserve the trapped backpressure by injecting mud into the annulus during connections.

Operationally, the plan for the lower part of the 6 ½” hole was to drill-in with casing from the bottom of the 6 ½” open hole section down to 11065 ft MD and to keep the well vertical. The static mud weight for the entire section was 15.7 ppg and the ECD was a constant 16.2 ppg. However, even before the first connection was made, up to 1220 units of gas was already flowing from the well. The gas volume steadily increased throughout the section rising as high as 1550 units towards the end of the section (Fig. 10).

In all, 13 pressure transitions were made in this hole section during which the ECD generated by the annular frictional pressure was replaced by backpressure created and controlled by the APD system. Of those transitions, 9 were for connections, 3 for rig pump failures, and 1 for top drive maintenance. In spite of the gas the APD system was still able to manage a constant BHP within an average window throughout the section of +/- 0.18 ppg (Fig. 11).

Shell accomplished its primary objective with the 3 ½” casing drill string and automated pressure drilling system by avoiding losses, managing high levels of continuous gas flow, and maintaining a constant ECD in the transition from drilling to connections even with the high levels of gas.

Managed Pressure Cementing One final task was left after drilling in the 3 ½” production tubing and that was to cement the casing in place while preserving their well earned previous achievements. Now the trick was going to be to avoid losing returns with the heavy weight cement. As before, Shell turned to the APD system to accomplish that objective by maintaining a constant BHP in the

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annulus during cementing operations.

The cementing operation was modeled using a constant pump rate of 3 bbl/min for the entire process. Before tying into to the cement head the rig circulated bottoms up until gains and losses were balanced at 3 bbl/min and the gas was circulated out of the annulus. During the reduced pump rate the APD choke was tuned and then programmed to hold 90 psi of backpressure during this circulation phase. Once steady returns from the well were established the rig pump was shut down to hook up the cementing unit to the cement head. During that procedure the APD system held the backpressure between 200 to 210 psi.

After a 5 bbl spacer was pumped the cement lines were pressure tested to 7500 psi for 5 minutes. From that point on, cement pump transitions were managed in 1 bbl/min increments to allow the choke the time to adjust and maintain the ECD constant at 16.2 ppg.

Once the top cement plug was dropped the pumps were brought up to speed to push the displacing fluid down the drill pipe. At Balance followed a closely controlled procedure to regulate the backpressure for a fixed volume of fluid displaced into the drill pipe (Fig. 12). That procedure carefully governed the effect that the 16.2 ppg cement had on the ECD as it filled the annulus. Careful regulation of the reduction in backpressure with the cement pump rate and close cooperation between the MPD and cementing crew resulted in a successful cement job without losses.

Summary The Bales 7 well was drilled with a new, modular automated pressure trapping system designed to manage constant BHP in narrow windows without the use of an automated backpressure pump during conventional and casing drilling operations and while cementing.

The system continuously managed pressure in 2365 ft of open hole drilled in 2 different sections and during 19 pump transitions without failure. During connections made with the 3 ½” casing drill string it demonstrated its ability to limit BHP fluctuations to +/- 0.18 ppg of a 16.2 ppg set point in a directional well over 11000 ft deep even with high levels of gas flow.

Rig-up took only 7 hours which represents a significant time savings – over 60% compared to offshore systems.

With this system Shell was able to extend their use of casing drilling to other fields in South Texas, prevent loses in severely depleted sands, and avoid the need for costly liner drilling contingencies.

Acknowledgements The authors acknowledge and thank their respective companies, Shell Exploration & Development and At Balance, for their permission to publish this paper.

References 1. Vogelsberg, P., “Liner Drilling with Managed Pressure Reduces Trouble in Depleted Sand Environment”, AADE

2009NTCE-10-02, presented at the 2009 National Technical Conference & Exhibition, New Orleans, La, 31 Mar.-3 Apr. 2009

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Fig. 1: Map of South Texas showing location of the McAllen-Pgarr fields (images coutesy of Texas RR Commission and Shell)

Fig. 2: Photo of the type of offshore MPD system used by Shell in the GOM. The photo on the left shows the choke manifold, backpressure pump, and Coriolis flow meter. On the right the photo shows the pressure relief choke installed at the wellhead.

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Fig. 3: Close-up photo of a skid mounted choke manifold. The choke labeled AC 3 is the pressure relief choke installed in the 3rd overhead leg which was removed to simplify the new design.

Fig. 4: Fig. 4: 3D drawing of the new modular manifold showing the location of the redundant chokes and the other main components.

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Fig. 5: Photo of the modular manifold rigged-up on the Bales 7 location in South Texas with a Coriolis flow meter, programmable logic controller, and a hydraulic power unit. This photo highlights the small footprint and simplified installation of the new design.

Fig. 6: Casing and hole size plan for the Bales 7 well. The modular automated pressure trapping system was used to drill 6 ½” open hole with no losses which allowed Shell to avoid the cost of the 5 ½” contingency liner drilling string. The APD system was also used with the 3 ½” casing string to drill the productin section to TD with no losses.

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Fig. 7: Vertical section plot for the Bales 7 well highlighting the open hole sections below the 7 5/8” casing shoe in which the pressure was managed by the APD system.

Fig. 8: Plot of ECD from one 24 hour period during which the APD system continuously managed backpressure to

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control the ECD.

Pump transition

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Min ECD 14.1 ppg

Fig. 9: Pressure plot highlighting the pump transitions at the start and end of a connection and the min and max fluctuations that occur during pumps off and on. During this connection the ECD window was 0.4 ppg (+/- 0.2 ppg).

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Fig. 11: Connection plot from the 3 ½” casing drilling operation. It shows the min/max window for ECD during this connection was 0.3 ppg (+/- 0.15 ppg). The slowly rising backpressure is due to the steady flow of gas from the well.

Fig. 12: During cementing operations for the 3 ½” drilled-in casing the APD system controlled the ECD between 16 ppg and 15.85 ppg by regulating the backpressure with the rate at which the cement was displaced in the drill pipe.