Summary
This study presents a new way to model high secondary porosity, mainly vuggy porosity, in naturally fractured reservoirs. New solutions are presented for two cases, one in which there is no primary flow through the vugs (which is an extension of the Warren and Root model) and one in which the dissolution process of pore throats has created an interconnected system of vugs and caves. In both cases, there is an interaction between matrix, vug, and fracture systems. New insights are provided.
Both pressure and production responses during transient and boundary-dominated flow periods are explored. In transient well tests, for the case in which there is no primary flow through the vugs, a change of slope could be present during the transition period. Thus, this study shows that slope ratios of 2:1 of an early- or late-time segment vs. a transition segment do not necessarily imply transient interaction between matrix and fractures. It is also shown that the presence of vugs and caves may have a definitive influence on decline-curve and cumulative production behaviors; therefore, it is necessary to incorporate vuggy porosity in the process of type-curve match.
Finally, the use of the methodology obtained in this work is illustrated with synthetic and field examples.
Introduction
Most of the world's giant fields produce from naturally fractured and vuggy carbonate reservoirs that have complex pore systems, mainly because carbonate rocks are particularly sensitive to post-depositional diagenesis, including dissolution, dolomitization, and fracturing processes. Complete leaching of grains by meteoric pore fluids can lead to textural inversion, which may enhance reservoir quality through dissolution or occlude reservoir quality through cementation.
Some works have classified carbonates on the basis of fabric-selective and nonfabric-selective pore types. The nonfabric-selective types are vugs and channels, caverns, and fractures. For the purpose of this work, no distinction is made on vugs, caverns, and channels, and they will be denoted by the term vugs. Thus, vugs may vary in size from millimeters to meters in diameter.
Vugs are the result of carbonate and/or sulfate dissolution. From core observations, the matrix-porosity types adjacent to the vuggy zones are moldic, solution-enlarged microfractures and solution-enlarged intercrystalline. Thus, it is possible to have a permeability enhancement adjacent to the vuggy zones.
Three porosity types (matrix, fractures, and vugs) are usually present in naturally fractured, vuggy carbonate reservoirs. The determination of permeability and porosity in vuggy zones from core measurements is likely to be pessimistic because of sampling problems. In areas lacking cores, openhole wireline logs may be used to help identify vuggy zones; however, vugs are not always recognized by conventional logs because of their limited vertical resolution.
Vuggy porosity is common in many carbonate reservoirs, and its importance in the petrophysical and productive characteristics of a carbonate rock has been recognized by several works.
Vugular porosity can be subdivided into connected and disconnected types. The effect of vugs on permeability is related to their connectivity. High permeability may be present in vuggy zones by solution enhancement of pore throats, which creates an interconnected system of vugs. The presence of high-porosity and high-permeability vuggy zones may diminish waterflood effectiveness and leave a large amount of bypassed oil in the lower-permeability matrix. One purpose of our work is to present a technique to identify high secondary porosity, mainly vuggy porosity.
It has been observed in the literature that vugular zones strongly influence production performance. This reference addresses the problem of modeling vuggy naturally fractured reservoirs, allowing the possibility of primary flow through vugs, and develops a method to identify vuggy reservoirs on well tests and decline curves, evaluate porosity associated with vugs and fractures, and determine vuggy connectivity.
The proposed model can be used in numerical simulators. Some comparisons between the results of analytical solutions derived in this work and those obtained with a numerical simulator, which uses the proposed model, are presented.
Decline curve analysis using a pseudo-pressure-based interporosity flow equation for naturally fractured gas reservoirs
