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

Colwart, George; Burton, Robert M.; Eaton, Luke F.; Hodge, Richard M.; Blake, Kenyon

doi:10.2523/105542-ms

Cited by 4 publications

(9 citation statements)

References 8 publications

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“…Eight of the nine Magnolia completions have produced without any sand production. 8 The wells are producing with near zero to negative friction adjusted skins, exceeding pre-project estimates of skins of five.…”

Section: Resultsmentioning

confidence: 81%

“…The A1ST1BP1 original completion subsequently failed during initial unloading and the information from both logs would have been extremely helpful in diagnosing the failure. 8 RA tracer and annulus pack density logs were subsequently run on all wells where the completion hardware allowed.…”

Section: Perforation Strategymentioning

confidence: 99%

“…The supercharged flow from the formation to the well was thought to have caused the screen failure on the second A1ST1BP1 frac-pack. 8 The information from the gauge data led to modifying the fracpack procedures to not shift the gravel pack service tool to a reverse position, which would allow the formation to flow into the well if the formation had been supercharged during the mini-frac treatment. This was a significant change to typical frac-pack procedures.…”

Section: Perforation Strategymentioning

confidence: 99%

“…8 The pressure / temperature gauges were run on all of the wells except two. These two wells were completed with stacked frac-packs where concentric isolation strings complicated the service tool geometry and diminished the temperature diagnostic benefits.…”

Section: Perforation Strategymentioning

confidence: 99%

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

Eaton

Reinhardt

Bennett

et al. 2007

SPE/IADC Drilling Conference

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TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractConocoPhillips 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 target multiple zones resulting in complex directional wells with 50°-60° maximum hole-angles. The wells are completed using dry trees from the TLP and are producing primarily from massive, fine-grained, Pleistocene-aged reservoirs.These reservoirs require sand-control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high rate, long life completions, the producing zones are frac-packed. The average perforated interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft.The typical production casing string for the wells consists of 10-3/4 in. casing with an 8-1/16 in. production liner. Drift diameter through the tapered production casing is 9-1/2 in. and 6-1/2 in. respectively. The 6-1/2 in. drift diameter allows using common size screens and packers. The wells are generally completed with a 4-1/2 in. x 3-1/2 in. tapered tubing string.Premium screens with shunt tubes are used on the wells due to the long deviated intervals.The "frac-pack" stimulation treatments are pumped at rates of 27 to 40 bbl/min with a viscoelastic surfactant carrier fluid. Washpipe conveyed downhole pressure and temperature gauges and radioactive tracers are used to help analyze the treatment results.This paper will discuss screen selection philosophy in silt/very fine sand reservoirs, carrier fluid selection, perforation strategy, and ability to frac across shale intervals. The paper will also cover the effectiveness of achieving a frac-pack with premium screens with shunt tubes, based upon downhole pressure, temperature, radioactive tracer information, and revised operational practices that resulted in zero to negative skin completions across long, perforated intervals that continue to produce sand free after extreme reservoir depletion.

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Section: Resultsmentioning

confidence: 81%

Section: Perforation Strategymentioning

confidence: 99%

Section: Perforation Strategymentioning

confidence: 99%

Section: Perforation Strategymentioning

confidence: 99%

See 2 more Smart Citations

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

Eaton

Reinhardt

Bennett

et al. 2007

SPE/IADC Drilling Conference

Self Cite

View full text Add to dashboard Cite

show abstract

“…Both tools were not run on the third well as a costsavings measure. The A1ST1BP1 original completion subsequently failed during initial unloading and the information from both logs would have been quite helpful in diagnosing the failure (Colwart et al 2007). Radioactive tracer and annulus-pack density logs were run subsequently on all wells where the completion hardware allowed.…”

Section: Post-job-analysis Toolsmentioning

confidence: 99%

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

Eaton

Reinhardt

Bennett

et al. 2009

SPE Drilling &Amp; Completion

Self Cite

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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 target multiple zones, resulting in complex directional wells with 50-60 maximum hole angles. The wells are completed using dry trees from the TLP and are produced primarily from massive, fine-grained, Pleistocene reservoirs.These reservoirs require sand control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high-rate, long-life completions, the producing zones are frac packed. The average perforated interval during the initial completion program was 310 ft, with a maximum perforated interval of 571 ft.The typical production-casing string for the wells consists of 10 3 / 4 -in. casing with an 8 1 / 16 -in. production liner. Drift diameter through the tapered production casing is 9 1 / 2 and 6 1 / 2 in., respectively. The 6 1 / 2 -in. drift diameter allows using common-sized screens and packers. The wells are generally completed with a 4 1 / 2 Â 3 1 / 2 -in. tapered-tubing string.Premium screens with shunt tubes are used on the wells because of the long deviated intervals. The "frac-pack" stimulation treatments are pumped at rates of 27 to 40 bbl/min with a viscoelastic-surfactant (VES) carrier fluid. Washpipe-conveyed downhole-pressure and -temperature gauges and radioactive tracers are used to help analyze the treatment results.This paper will discuss screen-selection philosophy in silt/ very-fine-sand reservoirs, carrier-fluid selection, perforation strategy, and ability to frac across shale intervals. The paper also will cover the effectiveness of achieving a frac pack with premium screens with shunt tubes, on the basis of downhole-pressure andtemperature and radioactive-tracer information, and will discuss revised operational practices that resulted in zero-to negativeskin completions across long, perforated intervals, which continue to produce sand-free after extreme reservoir depletion.

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Multiphase Well Rate Measurements Applied to Reservoir Analysis

Tosic

Mehdizadeh²

2008

Abu Dhabi International Petroleum Exhibition and Conference

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The new technology of multiphase measurement has been widely adopted by the oil industry. The meters that utilize this technology are either permanently installed or periodic usage such as well testing during the flow back, well appraisal, trials, etc. The consistent, reliable and accurate flow measurement plays an important role in reservoir and production engineering. However, the industry trends show that many practitioners do not fully utilize the potential of continuous on-line measurements for reservoir and production engineering assessments. This paper will show how online multiphase measurement data can be applied to reservoir and production analyses and how additional useful results can be obtained. Field examples from the Gulf of Mexico (GOM) will be presented to support the process. To begin with, the paper reviews the role of pressure transient analysis (PTA) and flux rate for assessing the health of the reservoir. PTA gives useful information about the health of the well (skin) and the reservoir properties. It is an established analysis methodology that requires two important inputs, bottom-hole pressure and flow rate. If the flow rates are not accurate, then the results from PTA would be erroneous. Also, the calculation of down-hole flow velocity would be incorrect. These uncertainties could result in wells to be produced below or above optimal levels. Either case would lead to production loss or well damage and the need for remedial work-over. Unfortunately, the maximum safe-rate term is not easy to predict. With high producing wells, minor measurement error can create significant errors in related calculations for reservoir or well parameters. For instance, if the well flow velocity in the formation exceeds the critical velocity for fines movement, the formation fines would start moving. Once they are moving, the additional near-wellbore region damage would be created or the screen may get eroded. Production data analysis (PDA) such as Rate Normalized Pressure (RNP) analysis in conjunction with continuous flow rate measurements, provided by online multiphase meter, can be used to obtain additional reservoir parameters. In the applications discussed in this paper, the flow rates from the multiphase meters were extensively used for reservoir and well surveillance, flow assurance and the well production allocation. Introduction With deepwater (DW) high investment wells, many operators have chosen continuous (real time) reservoir surveillance. Otherwise, the well is operated "blindly" and the risk for well loss is high 1,2,3,4. By doing continuous surveillance, one has an early warning of the well condition and remedial action can be taken immediately. In the GOM, most of the DW reservoirs are high-permeability reservoirs. Reservoir and the near wellbore region parameters are changing with time. Sound reservoir management requires monitoring of these changes. To develop these reservoirs, substantial investment is required. Also, once on production these reservoirs require constant surveillance (e.g. compaction, skin/permeability change, flow assurance, slug tracking, etc). Lack of surveillance or misinterpretation of well behavior could have detrimental consequences. Numerous examples of the failed wells have been reported in the literature.1 The most common well failure is screen erosion, which is caused by excessive fluid velocity across the screen area. The screen erosion, aggravated with fines and the fluid velocity, is directly proportional to the flow rate.

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

Cited by 4 publications

References 8 publications

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

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

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

Multiphase Well Rate Measurements Applied to Reservoir Analysis

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