Results

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.

Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.

In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pfb) during the injection period. As expected, the pfb always turns out to be higher than the fracture closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.

A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.

Summary

Permeability is the cornerstone of any reservoir-flow modeling that leads to field development and production management. Typical sources of permeability include cores, logs, wireline formation tests [or minidrillstem tests (mini-DSTs)], and conventional DSTs. However, integrating various sources of permeability at different scales is problematic. Anchored in mini-DST-derived permeability, this study endeavors to integrate various sources of permeability, leading to reservoir description in a turbidite sandstone reservoir in the Sabah basin, Malaysia.

Pressure-transient-test data recorded during a mini-DST operation differed significantly from data gathered during a conventional DST. Even though test quality was excellent, interpretation challenges were numerous in this well. Consequently, multidisciplinary information was brought to bear for integration of data derived from mini-DSTs. Other sources of information included sidewall cores, spot pressure measurements, nuclear magnetic resonance (NMR), and microelectrical imaging logs. This case study demonstrates that, in this particular setting, the use of mini-DSTs was cost-effective and yielded the subsurface information required to plan field-development options.

Summary

Estimating in-place volume associated with each well, leading to estimation of total reservoir in-place volume, is the cornerstone to any reservoir-management practice. Yet, conventional methods do not always lend themselves to routine applications, particularly when used in singular fashion. However, combining these methods on the same plot has considerable merit in that they converge to the same solution when material-balance (MB) -derived average-reservoir pressure is used in a volumetric system.

This study presents a systematic procedure for estimating the gas-initially-in-place (GIIP) volume when real-time surveillance data of pressure, rate, and temperature are available at the wellhead. Specifically, we show that log-log diagnosis, followed by combined static- and dynamic-MB analysis and transient-productivity-index (PI) analysis, leads to consistent solutions. Thermodynamic behavior of fluids is also explored to ensure that converted pressures at the bottomhole and measured rates have consistency and accuracy for reservoir-engineering calculations.

Layered systems were selected for this study because they represent most situations. Two synthetic cases probed issues pertaining to average-reservoir-pressure computation with the pseudosteady-state (PSS) approach, and two field examples validated the approach presented here.