Resolving Carbonate Complexity with Respect to Fluid Movements in Brown Fields

Carbonate rocks, unlike sandstones, have complex pore systems. These pore systems may have bi- or tri-modal pore size distributions. Pore sizes may range from a less than an inch to feet. The pore geometry of carbonate rocks is very heterogeneous and variable. The texture and structure of carbonate rocks are further rendered more complex by the digenesis caused by chemical dissolution, precipitation, dolomitization, leaching, and fracturing. Due to these reasons, petrophysical models comparable in terms of simplicity to the Archie equation have not been developed for carbonate rocks. In some petro physical analyses, the Archie equation is used to calculate water saturation in carbonate rocks. This approach could lead to significant errors.

This paper would discuss the uncertainties and complexities involved in evaluation of carbonate reservoir. This paper would describe the alternative approach which based on calculation of water saturation of carbonate rocks on data from Nuclear Magnetic Resonance (NMR) logs. The saturations calculated from the NMR logs are lithology independent. Brown fields usually are under water injection which makes even more difficult to predict the moveable fluid. The Secondary and tertiary porosity features such as vugs, dissolution channels and fractures complicate relative permeability relationships as well as contribute to problems with respect to the movable fluid. It is difficult to differentiate between zones with higher connate water saturation and those with injection water breakthrough or with extensive WBM invasion. As a result of these conditions water production in new drain holes is sometimes higher than anticipated. To address the problem of optimum drain hole placement a successful methodology was adopted in which Down Hole Fluid Analysis (DFA) and permeability profiling have been added to the conventional Wire line Formation Tester (WFT) pressure survey. This paper presents a case study which shows how completions done by acquiring the NMR logs and by mapping the fluid and permeability profiles throughout the target interval has resulted in far higher oil production than nearby wells placed solely on the basis of saturation estimation from open hole logs.

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California