Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development

Abstract

ConocoPhillips is developing the Magnolia field with a tension leg platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells produce primarily from thick, fine-grained, Pleistocene-age reservoirs. Due to the long lengths of the producing reservoirs and large variations in sand grain sizes/permeabilities, premium screens with shunt tubes in conjunction with cased hole frac packs have been used to complete the wells. The third well, A1ST1BP1, was completed using the same techniques as were successfully used on the first two wells. The A1ST1BP1 completion failed during initial unloading, allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and premium sand control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was re-perforated, new screens run and a second frac-pack pumped. When laying down the washpipe after the second frac-pack, erosion marks indicated an apparent second screen failure. A detailed examination of both A1ST1BP1 frac-pack jobs was conducted in conjunction with laboratory collapse and erosion testing of the premium screens. Collapse testing revealed the screen lost sand control at less than 1000 psi. The collapse rating stated by the manufacturer was greater than 7000 psi. The erosion tests demonstrated that inflow from supercharged reservoirs into the wellbore could erode hole(s) in the premium screen. Revised operational procedures were used in six subsequent frac-packs without any additional failures and zero to negative completion skins. This paper will discuss the failure modes of the two frac-pack/premium screen sand failures, workover planning and execution to remove tubing with multiple control lines and fish screens with shunt tubes from close tolerance casing, as well as procedural revisions developed to successfully frac-pack the subsequent Magnolia reservoirs. Introduction The Magnolia field consists of a series of highly faulted, compartmentalized, geo-pressured (12.2 to 15.0 lbm/gal), unconsolidated silt/very fine sand Pleistocene-age reservoirs. Due to the high degree of compartmentalization, a majority of the reservoirs produce under depletion and compaction drive with minimal water influx. Reservoir pressures have declined during production from initial pressures in the 11,000 psi (13 lbm/gal) range to expected abandonment pressures as low as in the 1500 psi (1.8 lbm/gal) range. These large reservoir pressure declines, on the order of 9,000 to 10,000 psi, are expected to generate large geotechnical loads on the wells. As a result, thick-walled production casing was installed to curtail compaction-related failure. The B25 Sand is the largest producing interval in the Magnolia field and has been a target for most of the field's frac-pack completions, including the A1ST1BP1 well. The reservoir properties of the B25 Sand are also similar to other pay intervals in the Magnolia field. The vertical height of the B25 ranges from 104 ft to 365 ft (127 ft to 595 ft measured depth [MD]) throughout the Magnolia field, with a high net to gross ratio of around 0.9. The sand is unconsolidated and consists of laminated, fine grained silt/sand with median (D50) grain diameters ranging from a few micrometers (µm) up to 80 µm, as shown in Figure 1. To maximize well productivity with minimum solids production, all wells in the Magnolia Field have been completed with cased-hole, frac-packs.1

Integrating Petrophysical, Geological and Geomechanical Modelling to Assess Stress States, Overpressure Development and Compartmentalisation Adjacent to a Salt Wall, Gulf of Mexico

“…1a). This field is under a water column of 1424 m (4674 ft) (Stomp et al, 2004;Eaton et al, 2005;Colwart et al, 2007). The Titan mini-basin depocenter has a thickness of approximately 11 km of Upper Miocene to Pleistocene sediments deposited on top of the allochthonous salt sourced from the Louann Jurassic salt formation (Fig.…”