Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
- George Colwart (ConocoPhillips Co) | Robert C. Burton (ConocoPhillips Co) | Luke F. Eaton (ConocoPhillips Co) | Richard M. Hodge (ConocoPhillips Co) | Kenyon J. Blake (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2009
- Document Type
- Journal Paper
- 144 - 156
- 2009. Society of Petroleum Engineers
- 3.2.5 Produced Sand / Solids Management and Control, 2.4.4 Screen Selection, 5.3.2 Multiphase Flow, 2.1.7 Deepwater Completions Design, 1.7.5 Well Control, 1.6 Drilling Operations, 4.5 Offshore Facilities and Subsea Systems, 3 Production and Well Operations, 4.1.5 Processing Equipment, 1.2.3 Rock properties, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating, 2.7.1 Completion Fluids, 2.2.2 Perforating, 1.8 Formation Damage, 2.4.3 Sand/Solids Control, 2.4.5 Gravel pack design & evaluation, 4.3.4 Scale, 4.2 Pipelines, Flowlines and Risers, 5.6.5 Tracers, 3.2.4 Acidising, 4.5.7 Controls and Umbilicals, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4.6 Frac and Pack, 2 Well Completion
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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 reservoirs. Because of 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 used successfully 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 a 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 reperforated, 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 that the screen lost sand control at less than 1,000 psi. The collapse rating stated by the manufacturer was greater than 7,000 psi. The erosion tests demonstrated that inflow from supercharged reservoirs into the wellbore could erode holes 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, and procedural revisions developed to successfully frac-pack the subsequent Magnolia reservoirs.
|File Size||4 MB||Number of Pages||13|
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