spe 128923 mpd cementing
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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, 24 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 doesnt 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 hole was drilled in with 3 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 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 Shells 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 Shells 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, Shells 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 Balanc