design led to consistently successful treatments (below). Modifications included optimizing the slip area, designing a more robust J-type latching mechanism, and adding two equalizing ports and a pressure-balance section to the emergency- release mechanism.
Because coiled tubing-conveyed fracturing often induces diffi cult-to-predict, variable loads and stresses greater than those normally encoun- tered by stimulation packers, Schlumberger developed software to optimize treatment designs and reduce excessive packer loads. This software can also be used to monitor job progress and make necessary corrections in real time. The new software and redesigned OptiSTIM MP packer were used on Well OML862, an oil producer completed with 41
⁄ 2 Pressure-balance section -in. cemented
production tubing and a 5-in. slotted liner. This well had communication between the 41
⁄ 2 ⁄ 8 -in. pro- Equalizing port J-type latch Drag blocks
High-strength slips with optimized contact area
Equalizing port
High-pressure elastomer element and anti-extrusion device
Adjustable shear-release system
-in. casing strings. The cemented pro- duction tubing made a conventional workover impossible. Performing a fracture treatment through coiled tubing isolated the wellbore tubulars from high treating pressures and abrasive proppants. With the packer set at 10,220 ft [3,115 m], a 10,000-gal [37.9-m3] calibration treatment pumped at 6.6 bbl/min [1 m3/min] and surface treating pressure of 9,400 psi [64.8 MPa] indi- cated a closure pressure of 10,300 psi [71 MPa], which gives a fracture gradient of 0.92 psi/ft [20.8 kPa/m]. The primary fracture treatment was pumped successfully at an average rate of 6.4 bbl/min [1 m3/min] with the packer set at 10,186 ft [3,105 m]. Sonatrach pumped 23,975 lbm [10,875 kg] of 20/40-mesh high-strength proppant at a maxi- mum bottomhole concentration of 4 ppa, placing a total of 21,529 lbm [9,765 kg] in the formation. When a screenout occurred 24 bbl [3.8 m3] before the end of the fl ush, the pump rate was reduced to stay below the maximum allowable treating pressure of 10,000 psi [68.9 MPa]. The packer was then released and any remaining proppant was circulated out prior to retrieving the packer. The packer was exposed to an average differential pressure of 5,500 psi [37.9 MPa] and a maximum differential pressure of 9,600 psi [66.2 MPa] at screenout. The well is producing 65 m3/d [409 B/D] while Sonatrach optimizes the gas-lift system.
duction tubing and 7-in. casing, and between the 7-in. and 95
> Selective stimulation with single-seal packers. The OptiSTIM MP mechanical packer is a multiple-operation, tension-set tool for coiled tubing or jointed pipe. This assembly is used for multizone CoilFRAC treatments when existing perforations or tubulars must be protected from treating uids and pressures.
Fracturing through coiled tubing in Hassi Messaoud field required modified packers and improved computer software to model downhole forces. These improvements increased the reliability of CoilFRAC treatments, which can now be performed in wells as deep as 12,000 ft [3,658 m]. Pumping rates can range from 8 to 25 bbl/min [1.3 to 4 m3/min] with 5 to 12 ppa. CoilFRAC technology can tap previously
bypassed gas reserves and optimize well produc- tivity, especially in low-permeability gas
reservoirs. The latest OptiSTIM ST straddle packer provides added fl exibility for selective iso- lation and stimulation of individual zones (next page, left). Reservoir applications from perforat- ing to selective zonal isolation and stimulation have generated several new downhole CT tools.
Advanced Downhole Tools
Effective zonal isolation for CT applications requires infl atable packers that can pass through tubing, expand and then seal in larger casing. In the past, these systems were rarely used in hostile environments because of expansion limi- tations and susceptibility to high temperatures and pressures, and corrosive fl uids or chemicals. Schlumberger developed the 21
⁄ 8 -in. single-ele-
ment CoilFLATE HPHT high-pressure, high-temperature through-tubing inflatable anchoring packer to address the limitation of con- ventional infl atable packers (next page, right).13 CoilFLATE HPHT packers extend critical con- centric zonal isolation to previously inaccessible downhole environments. These packers can be run in vertical, high-angle or horizontal well- bores on coiled tubing or on jointed pipe using a snubbing unit. This eliminates the need for a workover rig and allows remedial operations without killing the well. Tapered slats in the tool body, or carcass, allow narrow sections near the end of a packer to provide the required load-bearing cross section, while the wider sections provide the necessary extrusion barrier and coverage for the infl ation bladder. A CoilFLATE HPHT carcass restraint system (CRS), or internal crush sleeve, imposes a constant axial load on the slats during infl ation that creates tension on the packer to ensure pro- gressive inflation from the center toward both ends. This center-out inflation prevents end sections of the packer element from inflating first and trapping fluids, resulting in an ineffi- cient seal, or soft set.
The proprietary elastomer and packer ele- ments are resistant to hydrogen sulfide [H2S], carbon dioxide [CO2] and other chemicals. Steel parts in the 21
⁄ 8 -in. setting tool are replaced by
nickel-based high-strength alloy components to make the entire BHA fully H2S compatible. The composite elastomer bladder uses carbon fi bers to eliminate axial strain and allows the packer circumference to expand freely. This design provides a reliable seal at fi nal-to-
initial expansion ratios of greater than 3 to 1. CoilFLATE HPHT packers do not rely on a ball
13.Wilson S, Erkol Z, Faugere A, Eatwell B, Espinosa F and Xu R: “ In atable Packers in Extreme Environments,” paper SPE 89529, presented at the SPE/ICoTA Coiled Tubing Conference and Exhibition, Houston, Texas, USA, March 23– 24, 2004.
48 Oilfi eld Review
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