Summary

This paper presents new production decline curves for analyzing well production data from radial and vertically fractured oil and gas wells. These curves have been developed by combining decline-curve and type-curve analysis concepts to result in a practical tool which we feel can more easily estimate the gas (or oil) in place as well as to estimate reservoir permeability, skin effect, fracture length, conductivity, etc. Accuracy of this new method has been verified with numerical simulations and the methods have been used to perform analyses using production data from several different kinds of gas wells. Field and simulated examples are included to demonstrate the applicability and versatility of this technology.

These new production decline-type curves represent an advancement over previous work because a clearer distinction can be made between transient- and boundary-dominated flow periods. They also provide a more direct and less ambiguous means of determining reserves. The new curves also contain derivative functions, similar to those used in the pressure transient literature to aid in the matching process. These production decline curves are, to our knowledge, the first to be published in this format specifically for hydraulically fractured wells of both infinite and finite conductivity. Finally, these new curves have been extended to utilize cumulative production data in addition to commonly used rate decline data.

Introduction

Estimation of hydrocarbon-in-place and reserves for oil and gas reservoirs is needed from the time when such reservoirs are first discovered to future times when they are being developed by drilling step-out wells or infill wells. These estimates are needed to determine the economic viability of the project development as well as to book reserves required by regulatory agencies.

During the last 50 years, various methods have been developed and published in the literature for estimating reserves from high-permeability oil reservoirs to low-permeability gas reservoirs. These methods range from the basic material balance methods to decline-type curve analysis techniques. They have varying limitations and are based on analytical solutions, graphical solutions (known as type curves and decline curves), and combinations of the two. Examples of these range from Arp's1 decline equations for liquids to Fetkovich's2 liquid decline curves, Carter's3 gas type curves, and Palacio and Blasingame** gas equivalent to liquid decline curves. Other papers on this subject, too many to quote here, have appeared in the SPE literature.

Type-curve analysis methods have become popular, during the last 30 years, to analyze pressure transient test (e.g., buildup, drawdown) data. However, pressure transient data can be costly to obtain and may not be available for many wells, while well production data are routinely collected and are even available from industry databases. In the absence of pressure transient data, a method that can use readily available well production data to perform pressure transient analysis would be very beneficial. The result is the development of these new production decline-type curves.

Purpose

The purpose of this paper is to document new production decline- type curves for estimating reserves and determining other reservoir parameters for oil and gas wells using performance data. Depending on the amount of performance data available, these methods can provide lower-bound and/or upper-bound estimates of a well's hydrocarbon-in-place. The accuracy of such estimates for reserves and other reservoir parameters will depend on the quality and kind of the performance data available.

It will be demonstrated and confirmed, using the methods of Palacio and Blasingame,** that solutions for constant rate or constant bottomhole pressure production for oil and gas wells can be converted, in most cases, to equivalent constant rate liquid solutions.

First, we will review background material. Next, we will briefly discuss various methods which are commonly used for estimating gas reserves. Finally, we will present the new production decline-type curves and demonstrate their utility and application by means of both synthetic and field examples. Although the technology discussed in this paper is applicable to both oil and gas wells, our discussion will be limited mainly to gas wells.

Background Material
Transient and Pseudo-Steady-State Flow Conditions.

When a well is first opened to flow, it is under a transient condition. It remains under this condition until the production from the well affects the total reservoir system. Then, the well is said to be flowing under a pseudo-steady-state (pss) condition or a boundary-dominated flow condition. Transient rate and pressure data are used to determine reservoir permeability and near-wellbore condition (damage or improvement), fracture length, and/or fracture conductivity, whereas pss data are required to estimate the fluid-in-place and reserves. Transient and pss flow conditions are schematically shown on a Cartesian graph in Fig. 1 and on a log-log graph in Fig. 2.

Review of Various Reserve Estimation Methods.

The volumetric method is used to make an initial estimate of gas-in-place using petrophysical data such as hydrocarbon porosity, pay thickness, initial reservoir pressure, reservoir temperature, pressure-volume-temperature (PVT) data, and reservoir size (or well spacing). Such estimates are useful and should be made whenever possible.

Transient and Pseudo-Steady-State Flow Conditions.

When a well is first opened to flow, it is under a transient condition. It remains under this condition until the production from the well affects the total reservoir system. Then, the well is said to be flowing under a pseudo-steady-state (pss) condition or a boundary-dominated flow condition. Transient rate and pressure data are used to determine reservoir permeability and near-wellbore condition (damage or improvement), fracture length, and/or fracture conductivity, whereas pss data are required to estimate the fluid-in-place and reserves. Transient and pss flow conditions are schematically shown on a Cartesian graph in Fig. 1 and on a log-log graph in Fig. 2.

Review of Various Reserve Estimation Methods.

The volumetric method is used to make an initial estimate of gas-in-place using petrophysical data such as hydrocarbon porosity, pay thickness, initial reservoir pressure, reservoir temperature, pressure-volume-temperature (PVT) data, and reservoir size (or well spacing). Such estimates are useful and should be made whenever possible.

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