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

Long term productivity is impacted by both the magnitude and rate of skin growth during the life of the well. Many deepwater Gulf of Mexico (GOM) Operators experience premature Productivity Index (PI) decline, which significantly impairs the economics of many major capital projects (MCP). Stringent application of best practices in both design and execution phases of deepwater wells can alleviate premature skin growth during the well life. The current study summarizes some critical best practices that impact the rate of PI decline in a broad dataset of recent cased hole frac pack (CHFP) completions. This study outlines a methodology to assess the relative impact of numerous variables that affect the frac pack deliverability. Application of this methodology requires early project phase development of a 3D mechanical earth model optimizing the number and location of drill centers and associated well paths ensuring they are optimal for frac pack completions. The methodology includes the completion phase, and that the assessment of completion-execution performance is fed back into the planning of future wells. This feedback loop across deepwater projects identifies best practices in execution and continual improvement in future completions. Over 70 CHFP completions in six different deepwater fields are assessed and correlated to their productivity trends. Information from this broad dataset helps to develop new and confirm established best practices. These best practices are derived by cross-functional analysis of factors related to the reservoir, completion-design, execution and the effects on long term deliverability of these wells. Our analysis concluded that three specific factors showed the highest impact in achieving a successful CHFP with improved initial skins and anticipated lower rate of skin-increase with reservoir pressure decline. While many sub-factors contribute to their relative impact, these three key factors include: 1) fracture- wellbore connectivity; 2) sufficient fracture-width and conductivity in the near-wellbore region to withstand changing reservoir conditions; and 3) an undamaged and intact annular proppant pack. The details associated with improving the likelihood of achieving each of the key factors and other findings are explored in-depth in the current work. Consideration of these high-impact variables and other best practices is-assessed and quantified within the new workflow, providing feedback to improve future completions and MCP developments. Our data set provides the most comprehensive collective study of frac pack completions in the Gulf of Mexico. Furthermore, the cross-functional expertise that contributed to the analyses of sub-variables brought the "best minds to the table". These attributes and the wide number of variables that were examined outline key best practices that should apply to any CHFP execution. The improved completions- workflow and comparison between producing CHFP completions allow prediction of future productivity trends. Possession of this knowledge enhances the predictability of production forecasting for business planning purposes.

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.

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.

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.