SPE 136805 Pore-Type Determination From Core Data Using a New Polar-Transformation Function from Hydraulic Flow Units Rodolfo Soto B. /SPE, Digitoil, Duarry Arteaga, Cintia Martin, Freddy Rodriguez / SPE,PDVSA Western Division Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference in Lima, Peru, 1–3 December 2010. 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. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract A new sigmoidal function from polar transformation enables more accurate identification of pore types in fractured/vuggy reservoirs. The function is based on a polar transformation that separates the pore systems into two regions—matrix systems and fracture/vug systems—on the basis of hydraulic properties, reservoir quality index (RQI), flow-zone index (FZI), and normalized porosity. The polar transformation exhibits a hyperbolic distribution for intergranular/intercrystalline pore sample types at the point where they deviate from the trend so that we can identify pore types more accurately. Our new function has been validated from image log data from wells of Lagomar and/or Lagomedio fields and core data from different fields around the world, and we are certain that it will be of great help to the geoscientist when doing a reservoir characterization. Introduction A great number of reservoir systems are made up of different lithologies and pore types. The pore types could be matrix, fractures and vugs or a combination of these. For example, Nelson (2001) defined four types of reservoirs to characterize matrix and fracture systems: • Type 1 reservoirs, where fractures provide all of the storage capacity and permeability. This type of reservoir includes the unconventional fractured granite basement reservoirs of the Cuu Long basin in offshore Southern Vietnam and the Amal reservoir in Libya. • Type 2 naturally fractured reservoirs, where the matrix has negligible permeability but contains most if not all the hydrocarbons. This type of reservoir includes the shale gas reservoirs in the United States, which contain up to 780 Tcf of gas (Franz. and Jochen, 2005); the volcaniclastic reservoir in Cupen Mahuida field, Neuquén, Argentina (Zubiri and Silvestro, 2007), and Agha Jari in Iran. In these reservoirs, natural fractures provide permeability and the matrix provides storage of most of the hydrocarbons. • Type 3 reservoirs, where the matrix already has good primary permeability. The fractures add to the reservoir permeability and can result in considerably high flow rates. Oil is trapped in both the matrix and fractures. Examples of Type 3 reservois are the giant Kirkut field in Iraq, Ghawar field of Saudi Arabia, Gachsaran in Iran, Dukhan in Qatar, and the big Cusiana field of Colombia. These reservoirs are some of the most prolific producers. • Type 4 reservoirs, where the fractures are filled with minerals. Fractures provide no additional porosity or permeability but create a significant reservoir. The definition of these four types of reservoirs, based on matrix and fracture systems, does not cover all the pore systems present in the real world, and in general, one of the potential problems when more than one pore type is present in a reservoir is related to nonreconigtion of one of the them on plug samples and reservoirs. Determining the kind of pore types in core and log data is not easy. Consequently, petrophysicists and geologists developing petrophysical models often erroneously apply the methodologies and equations designed for intergranular/intercrystalline reservoir systems to complex systems (intergranular/ intercrystalline, fracture, and/or vug pore type). However, if we have a complex pore type system, the cementation exponent, m, is not constant but variable; and changes in the cementation exponent value can greatly affect water saturation calculated by the Archie equation, affecting the original oil in place (OOIP), the reserves, and the evaluation of potential pay zones. Often, the difference between economic and noneconomic production