Evaluation of a Horizontal Gas-Condensate Well Using Numerical Pressure Transient Analysis
Authors: Harisch R.A. , Bachman R.C. , Puchyr P.J. 
Published: December 2007

Abstract
This paper will describe the evaluation of a horizontal gas-condensate well using numerical pressure transient analysis techniques. The reservoir contains near critical fluid which exhibits significant liquid dropout when subjected to depletion. The paper will describe the experimental work performed, its mathematical characterization and the matching of both a well test and long-term production data with an extended black-oil reservoir simulation model. The focus of the work was to determine how the multiphase flow effects impact test interpretation and how liquid dropout would affect the long-term production performance of the well.
One of the important practical aspects was resolving production data at different separator conditions. The difficulties in characterizing near critical fluids and their impact on the test interpretation will also be reviewed.

Introduction
Gas-condensate systems are becoming increasingly important as higher pressure and temperature reservoirs are exploited. In many instances, the economic value of the condensate production far outweighs that of the gas. As a result, it is vital to accurately characterize the reservoir and reservoir fluids in order to maximize fluid recoveries and to accurately project future cash flows.
This paper examines techniques to analyze gas-condensate systems using the extended black-oil model suggested by Coats1. To this end, a discussion of methods to convert laboratory PVT data (constant volume depletion and constant composition expansion experiments) to an extended black-oil PVT model is provided.
As the pressure in the reservoir declines in a typical gas-condensate system, condensate drops out of solution, impeding the flow of gas due to relative permeability effects. At lower pressures, however, it is possible for some of the condensate to re-vaporize into the gas phase. This complex PVT behaviour requires the use of numerical rather than conventional analytical solutions to analyze well test behaviour and to predict future production performance.
An extended production test on a horizontal well located in a gas-condensate system was used as a case study. Initially, a single-point well test was conducted with an extended shut-in period exceeding one month. Subsequently, the well was placed on production. Since permanent downhole gauges were installed in the well upon initial completion, it was possible to analyze the long-term production as part of the well test. Prior to the well test, a series of fluid samples were collected and constant volume depletion (CVD) and constant composition expansion (CCE) tests were conducted on the fluid samples. The laboratory experiments allowed derivation of extended black-oil PVT properties for use in the numerical modelling of the well test and long-term production history of the well.
In general, well tests with their limited production times and, correspondingly, limited investigation depths into the reservoir often yield non-unique solutions. It was anticipated that the long-term production and pressure data available for the well would allow for a more unique reservoir characterization.
The intent of the case study was to characterize the reservoir and reservoir fluid properties, initial fluid distributions, assess the impact of multiphase flow on the well test and to predict future production performance for the well. Of particular importance was the estimation of a long-term deliverability profile for purposes of nominating gas plant capacity and for project economic purposes.