Abstract
Permeability contrasts associated with clinoforms have been identified as an important control on fluid flow and hydrocarbon recovery in fluvial-dominated deltaic parasequences. However, they are typically neglected in subsurface reservoir models or considered in isolation in reservoir simulation experiments because clinoforms are difficult to capture using current modeling tools. A suite of three-dimensional reservoir models constructed with a novel, stochastic, surface-based clinoform-modeling algorithm and outcrop analog data (Upper Cretaceous Ferron Sandstone Member, Utah) have been used here to quantify the impact of clinoforms on fluid flow in the context of (1) uncertainties in reservoir characterization, such as the presence of channelized fluvial sandbodies and the impact of bed-scale heterogeneity on vertical permeability, and (2) reservoir engineering decisions, including oil production rate. The proportion and distribution of barriers to flow along clinoforms exert the greatest influence on hydrocarbon recovery; equivalent models that neglect these barriers overpredict recovery by up to 35%. Continuity of channelized sandbodies that cut across clinoform tops and vertical permeability within distal delta-front facies influence sweep within clinothems bounded by barriers. Sweep efficiency is reduced when producing at higher rates over shorter periods, because oil is bypassed at the toe of each clinothem. Clinoforms are difficult to detect using production data, but our results indicate that they significantly influence hydrocarbon recovery and their impact is typically larger than that of other geologic heterogeneities regardless of reservoir engineering decisions. Clinoforms should therefore be included in models of fluvial-dominated deltaic reservoirs to accurately predict hydrocarbon recovery and drainage patterns.
Highlights
Fluvial-dominated deltaic reservoirs commonly exhibit pressure compartmentalization, poor sweep efficiency, early water breakthrough, and lower than expected ultimate recovery of hydrocarbons (e.g., Begg et al, 1992; Tye et al, 1999)
The aim of this paper is to quantify the impact of uncertainty in clinoform distribution and clinoform-related heterogeneity on fluid flow during hydrocarbon recovery from multiple, stacked, fluvial-dominated delta-lobe deposits in the context of (1) uncertainties in reservoir characterization, including the orientation and continuity of stacked delta-front parasequences, and associated channelized sandbodies and the impact of bed-scale heterogeneity on vertical permeability; and (2) reservoir engineering decisions, including oil production rate
We find that modeling FC sandbodies and non-zero vertical permeability in the distal delta-front heteroliths (dDF) facies association can have a significant positive effect on hydrocarbon recovery when clinoforms are present with a 90% barrier to flow along them
Summary
Fluvial-dominated deltaic reservoirs commonly exhibit pressure compartmentalization, poor sweep efficiency, early water breakthrough, and lower than expected ultimate recovery of hydrocarbons (e.g., Begg et al, 1992; Tye et al, 1999) These reservoirs consist of multiple stacked delta lobes, juxtaposed with coastal-plain and channel-fill deposits. Deveugle et al (2011) created a reservoir-scale, 3-D model of multiple stacked deltalobe deposits in an outcrop analog and found that sweep efficiency in stacked delta-lobe deposits is controlled by the orientation, continuity, and permeability of channelized sandbodies and by the vertical permeability of laterally extensive heterolithic distal delta-front deposits that form the lower part of each lobe
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