Characterizing Horizontal Well Performance in a Tight Gas Sand Using Pressure Transient, Production Logging and Geological Data
Authors: Churcher P.L. , Kenny J. , Lamb D.H. , Flach P.D. 
Published: December 2007

Abstract
Pressure transient analysis is routinely used to determine insitu reservoir parameters and the deliverability of vertical gas wells. It can also be used to determine these same parameters in a horizontal gas well using techniques similar to vertical well test analysis. The interpretation of the data can be substantiated using other sources of information such as production logging, gas production while drilling, and geological and numerical simulation models. Data obtained from an experimental vertical and horizontal underbalanced drilling program conducted in the Westerose Field in 1994 and 1995 is used to demonstrate the power of this reservoir management tool. The results indicate that the vertical permeability is too small to economically produce from unstimulated horizontal wells in the tighter interbar sands, and consequently fracture stimulation will be required.

Introduction
The Westerose Gas Field is located in central Alberta, Canada, approximately 75 km south of the city of Edmonton (Figure 1). Rich gas, containing up to 300 m3 of liquids per 1 × 106 m3 of gas (46 bbls per mmscf), is produced from the tight sandstone of the lower Cretaceous Glauconitic Formation at an average depth of 1850 m (6050 feet) and an average reservoir pressure of 15.5 MPa (2550 PSI). The original gas in place for this field is estimated to be 30 × 109 m3 (1.2 Tcf).
The Glauconitic Formation in this area was deposited as part of the Hoadley Barrier Bar-Barrier Island Complex. The sands are typically 20 to 30 m thick (60 to 90 feet) and can be subdivided into an upper, permeable sand (1 to 10 mD in core at benchtop conditions) and a lower tight sand (generally less than 0.5 mD in core at benchtop conditions). The upper and lower sands are separated by an impermeable shaley siltstone, informally referred to as the Middle Glauc Shale (Figure 2).
The reservoir quality of the lower sand is relatively uniform throughout the area, but the upper sand is highly variable. In some cases the upper sand forms permeable barrier bars that trend NE-SW. In other cases the upper sands are similar in reservoir quality to the lower sands. These sands are referred to in this paper as interbar sands. There are at least five bar sand trends in the area of the pilot that are separated by tighter interbar sands. Measurements of the regional stress orientation from recent ultrasonic borehole images of an open hole fracture stimulation treatment indicate that the maximum principle stress orientation runs parallel to the main bar trends.
An experimental drilling pilot project was conducted in this field in September 1994 to test the feasibility of accessing rich gas reserves in a tight sandstone reservoir using underbalanced drilling technology. The results from a lab study indicated that a carefully designed underbalanced drilling fluid would result in a substantial reduction in the formation damage and would likely dramatically improve the productivity of these damage-prone sands.
The first phase of this project involved drilling four vertical wells and setting casing to the top of the sand. The pay zone was then drilled out underbalanced using coiled tubing. The results of this program are documented elsewhere. Both pre and post-frac pressure transient analysis were conducted on two of these wells. Some of these data have been used in this paper to support the interpretations made using the horizontal pressure transient data.
The success of the vertical well pilot led to the implementation of a horizontal underbalanced pilot program in December of 1994. The first well drilled in this program, 3-33-44-2WS, targeted both the upper and lower sands. Although no full flow and build-up data was gathered for this well, a partial build-up analysis conducted on the lower sand in the heel of the well during drilling showed that the Middle Glauc Shale likely represents a regional permeability barrier.
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