Well Test Analysis Of A Naturally Fractured Gas Reservoir - A Case History
Authors: Aguilera R. , Au A.D. , Franks L.N. 
Published: March 2010

Abstract
Transient pressure analysis of wells in the Palm Valley Gas Field Of Australia was first discussed in the literature in 1976 and rapidly became a classic example of how to analyze well testing data of a naturally fractured reservoir using type curves(1).
The data have been re-evaluated in light of a larger production history and more detailed methods for transient pressure analysis of dual-porosity systems developed during the last few years. The re-evaluation includes the use of type curves, pressure derivatives, specialized crossplots and a dual-porosity numerical simulator.
The conclusion has been reached that evaluations of Palm Valley transient pressure data presented previously in the literature are faulty because of a lack of technology adequate to analyze these complex systems at that time. The current interpretations are presented in detail.

Introduction
The Palm Valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Fig. 1), approximately 120 km southwest of Alice Springs, The structure is an arcuate anticline mapped from surface expression and seismic data. (Fig. 2). The western and eastern plunges of the anticline are poorly defined, however, the anticline axis can be traced for over 40 km(2–5). Gas has been found in the lower Stairway sandstone, the basal Hom Valley siltstone, and the Pacoota sandstone, all within the Larapinta Group of Ordovician Age.
Production from the field commenced in August 1983 with the completion of an 8 in. pipeline to Alice Springs, Natural gas has been used as a replacement for liquid fuels in electricity generation. Gas production from the field has increased steadily, currently averaging 141 000 standard m3/d (5 MMSCFD) to Alice Springs.
In September 1986, a 14 in. trunk pipeline was completed connecting the field to the city of Darwin, 1300 km to the north, and to several major towns en-route. Production for this pipeline has reached 622 000 standard m3/d (19 MMSCFD) and again has been used as a liquid fuel replacement in electric power generation.
Development of the field has followed the definition of reserves and during the past 24 years, estimation of the gas reserves has been the subject of many studies; the most significant being by Strobel et al.lu in 1976; a reservoir simulation study by van Poollen and Associates in 1985 and a recent reserves study by Servipetrol Ltd, in 1990. These studies quantified reserves of 1.08 × I09 standard m3 (38.2 × 109 SCF), 9.2 × 109 m3 (325 &gt; 109 SCF), and 19.25 × 109 m3 (680 × 109 SCF), respectively, and reflect the increasing contribution of production history and technological advances. To July 1991, 1.20 × 109 standard m3 (42.3 × 109 SCF) had been produced from the field over its 24-year life and this now provides valuable history for reserve studies.
Technological advancements in dual-porosity systems for both well testing and reservoir simulation have allowed both fracture and matrix properties to be quantified without this technology early studies were based on incorrect theoretical assumptions and consequently produced incorrect answers.