Magnolia Deepwater Experience—Frac Packing Long, Perforated Intervals in Unconsolidated Silt Reservoirs

Eaton, Luke F.; Reinhardt, W.R.; Bennett, John S.; Morales, Hugo; Blake, Kenyon J.

doi:10.2118/105541-pa

Cited by 4 publications

References 9 publications

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

Colwart

Burton

Eaton

et al. 2009

SPE Drilling &Amp; Completion

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Summary 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.

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

Colwart

Burton

Eaton

et al. 2009

SPE Drilling &Amp; Completion

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Completion Design for a Highly Compacting Deepwater Field

Procyk

Jamieson

Miller

et al. 2009

SPE Drilling &Amp; Completion

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Summary The Magnolia field, located in the deepwater region of the Gulf of Mexico, produces oil and gas from a tension leg platform (TLP) in 4,673 ft of water. The reservoirs comprise several stacked sandstone intervals within the early to mid Pleistocene with some minor production from the Miocene and Pliocene sands. A total of eight wells have been completed, with the majority of the production from the B25 sandstone. The formation-particle size is fine-grained sand to coarse silt and has relatively low K*H compared to other deepwater reservoirs. The reservoirs are significantly overpressured, highly compartmentalized, highly compacted, and have experienced significant pressure declines in excess of 8,000 psi in some cases during production. The wells were completed with cased-hole frac packs and each completion included a permanent downhole gauge, enabling interpretation of the K*H and skin throughout the producing history of the wells to date. The perforating guns, frac fluids, and screens were extensively tested before completion. The perforation-shot size and density was carefully chosen and tested to achieve the required production. Well test results matched inflow analysis predictions. The initial skin values generally met expectations and improved during production because of a combination of well cleanup and reduced reservoir permeability from compaction. Proppant integrity has been maintained under extreme depletion (>8,000 psi) conditions. Productivity was measured using perforation tunnel permeability (Kpt) analysis. The Kpt values were analyzed over the course of production and compared to similar type completions. The Kpt benchmark analysis shows that the completions are among the best in class. Well productivity has met or is above expectations, and the longevity has exceeded expectations in most cases.

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Quantitative Frac Pack Analysis Using Dual Tracer Logs and Down Hole Gauges

Sanford¹,

Bruton²,

Woomer³

et al. 2010

All Days

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A combination of multiple down hole gauges and dual density / tracer logs were utilized to quantitatively evaluate distribution of fluid and proppant across a long perforated interval separated in two lobes and to quantify the annular pack percentage across the entire completion interval during a deepwater frac pack treatment in GoM. It was important to evaluate the achievement of an effective fracture in both lobes and define the annular pack percentage across the entire completion interval to be able to produce the well to its potential.This technique quantitatively evaluated the entire frac pack process and determined screen out events in separate lobes and annular pack efficiency. The analysis also defined the dynamics of the treatment fluid and proppant slurry movement during the frac pack pumping operation and their final placement.Several expected as well as unexpected conclusions and observations were identified. In summary, the diagnosis indicated that higher percentage of treatment fluid and proppant was received by the upper sandstone lobe. The exact proppant concentration at lower lobe screen out was identified. A baseline pre-pack value was established, which allowed the annular pack percentage to be calculated across the entire interval. It also provided detailed information on the sequence of events during washout at the crossover tool. All of these allowed the operator to confidently maximize deliverability from the subject well, which is currently producing 110 MMcfd.The results from this case history and the technique described should result in a step change in frac pack evaluation. Quantitative evaluation eliminates any doubts about the effectiveness of the annular pack and allows operators to produce their assets at maximum deliverability. Additionally, it assists future completion designs and type selection.

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Magnolia Deepwater Experience—Frac Packing Long, Perforated Intervals in Unconsolidated Silt Reservoirs

Cited by 4 publications

References 9 publications

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

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

Completion Design for a Highly Compacting Deepwater Field

Quantitative Frac Pack Analysis Using Dual Tracer Logs and Down Hole Gauges

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