Abstract

Improvements in stimulation technology have continued to increase our ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field, in Southwest Wyoming is a classic example of a reservoir that was commercialized with newer stimulation technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with reservoir permeability to gas less than 10 µD. Completion techniques have evolved over the years employing a variety of hydraulic fracturing techniques. In the past 2 years three techniques have emerged as the predominant completion methods: traditional nitrogen assist, induced stress diversion, and the use of flow thorough composite bridge plugs. This study evaluates the different techniques using spatial sampling to compare each well to its offsets and identify the completion scheme that yields the best results on cumulative production. From this study a clear best practice for completing wells in the Jonah field to maximize production was determined.

Introduction

Jonah field is located in the northwestern corner of the Green River foreland basin (T28 - 29N, R108W) (Fig. 1) between the Wyoming Thrust Belt to the west and the Wind River Mountains to the east. The field is 60 miles north of Rock Springs, Wyoming. By the end of 2000 over 200 commercial wells have been drilled on 40-acre spacing. The eastern (downdip) edge of the field is still being extended. The known limits of the field currently exceed 38 square miles.

Jonah field is bounded on the south and northwest by two wrench faults. Faults within the field boundaries add to the complexity of the reservoirs. Wells within the field encounter overpressured gas at 8,100 to 9,300 ft (0.58 to 0.65 psi/ft gradient) whereas nearby wells drilled across the bounding faults find normal pressure gradients at similar depths.

The Lance formation is Upper Cretaceous in age and consists of 2,000 to 3,000 ft of interbedded fluvial sands, mudstones, and coals. Individual sandstone units range from 5 ft to over 50 ft in thickness and have areal extents ranging from a few acres to 100 acres. Individual sands are geologically heterogeneous reservoirs because of their depositional shapes, but certain stratigraphic intervals consistently have sands developed. Sand-rich intervals are locally called the Upper Lance, Middle Lance, Jonah, Yellow Point, Wardell, and Upper Mesaverde (or Rock Springs). Total net sand in the field ranges from 300 to 600 ft of stacked net pay. Drilling depth ranges from 11,000 to 12,500 ft depending on how many sand packages an operator believes to be economical to develop. More specific geological descriptions can be found in references.1,2

Sand porosity ranges from 5 to 14% with relative gas permeability ranging from 0.001 to 0.02 md. Water saturation varies between 30 to 60%; currently there is no significant water production in the field. The producing condensate yield is between 8 to 10 bbl/mmscf with an API gravity of 52°. PVT fluid data are scarce, although the fluid composition appears to be very similar throughout the entire productive section.

Due to the low permeability of the Lance formation in this area stimulation is required for economical production rates. Although all operators use hydraulic fracturing for stimulation there are a variety of different treatment types, fracture isolation methods, and time between treatments.3,4 Until 1998 the typical treatment consisted of treating three to six individual sands per fracture treatment with the limited entry technique. A total of four to six fracture treatments were performed per well. After a fracture treatment the well was flowed back for 1 week or longer to clean up. Several methods were used to isolate each fracture treatment including pumping a sand plug to cover previous stages to running wireline set tubing retrieve bridge plugs.

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