Short Radius Horizontal Well in a Shallow, Unconsolidated Sandstone
Authors: McMann R.E. , Burger R.M. , Stephens B.P. 
Published: December 2007

The challenge of reducing drilling cost is no longer the sole responsibility of drilling engineers. A team approach is imperative to develop prospects that will achieve production and reserve recovery objectives in the most cost-effective manner.

After considering numerous criteria with regard to geology, reservoir characteristics, production, drilling, and completion operations, a short radius horizontal prospect was developed to exploit a shallow, water drive, sandstone reservoir in South Louisiana.

Introduction

The Lafitte Field is located approximately twenty-five miles south of New Orleans. Over six hundred wells with more than fifty producing horizons have been drilled in this field since its discovery in 1935.

Lafitte Field is a complexly faulted rollover anticline situated over a deep-seated salt feature. The productive interval in Lafitte ranges in age from Middle Miocene to Pliocene at depths from 3,000 ft. to 12,000 ft. The shallow section (3,000 ft. to 5,000 ft.) is dominated by fluvial and inner-shelf deltaic sands and shales. Amplitude maps, generated from a 3-D seismic survey acquired in 1991, revealed complex fluvial channel systems at several stratigraphic intervals, including the 3900' s and.

The State Lease 356 L. A. Marrero #32 well was drilled to deplete remaining reserves in the 3900's oil sand. The 3900's sand has produced over 5.1 MMBO, 1.5 BCGF, and 22MMBW field-wide. The fluvial channel reservoir into which the SL Marrero #32 well was drilled has produced 2 MMBO, 0.7 BCFG, and 8.7MMBW from 9 vertical wells. The average producing rate from the vertical wells for the first six months of production was 98 BOPD and all but one were producing with 50% water cut within the first four months.

Because of a strong bottom water drive, relatively low gravity, and high permeability, vertical wells experienced severe water coning problems. A horizontal completion was proposed as a means to minimize coning while improving production rates and recovery. It was projected that a horizontal completion could accelerate depletion of the reservoir over multiple vertical completions. The completion was designed for withdrawal rates of approximately 3000 BPD (gross fluid) once producing water on gas lift. The offset vertical completions had maximum withdrawal rates of 1100 BPD during their lives.

Planning

Design Considerations

When the team decided this prospect was a good horizontal candidate from a reservoir standpoint, two options were considered as to how to cost-effectively drill the well and minimize any environmental impact. They were:Sidetrack from an existing wellbore, orDrill a new well from an existing location.

The risks involved with sidetracking from an existing wellbore included salvaging 7" production casing below the 10-3/4" surface casing set at 1200 ft. and getting a good cement plug to sidetrack off in a washed out hole.

Drilling a new well from an existing slip meant having to start the directional work at a shallower depth in very soft formations.

The azimuth of the horizontal portion of each option also played a role in deciding where to drill from. The sidetrack option would be drilled parallel to the crest of the anticline, but would be slightly downdip of the highest part of the reservoir. A new well would be drilled across the highest part of the reservoir.

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