Technique Evaluates Polymer Injectivity in High-Salinity/High-Temperature Carbonates
Authors: Carpenter Chris 
Published: July 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211451, “Assessment of World-First Two-Polymer Injectivity Tests Performed in Two Giant High-Salinity/High-Temperature Carbonate Reservoirs Using Single-Well Simulation Models and Pressure-Falloff Analysis,” by Juan M. Leon, Shehadeh K. Masalmeh, SPE, and Ali M. Al-Sumaiti, SPE, ADNOC, et al. The paper has not been peer reviewed.

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The complete paper presents the interpretation of two polymer injectivity tests (PITs) performed in two giant light-oil high-salinity/high-temperature (HS/HT) carbonate reservoirs onshore Abu Dhabi. The detailed data acquired in both tests were used to evaluate both polymer injectivity at representative field conditions and in-depth mobility reduction. The interpretation of the pressure transient analysis (PTA) of the pressure falloffs (PFOs) and the mechanistic 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of future interwell pilots.

Introduction

The reservoirs tested in the PITs can be described as heterogeneous carbonate reservoirs divided into upper and lower zones. Upper-zone porosities range between 20 and 30%; permeability ranges from 10 to 1000 md. In contrast, the lower zone has porosities and permeabilities ranging from 10 to 30% and from 1 to 20 md, respectively. The main production mechanisms in the reservoirs are peripheral water injection, middip-pattern water injection, and crestal hydrocarbon gas injection in the gas cap.

The reservoirs have been developed through long horizontal wells oriented into the lower zones to allow a more-homogeneous sweep. However, the injected fluids in the lower zone travel quickly through the upper zone not far from the injection wells and around the producers into the lower zone. This water or gas inverse coning results in bypassed oil in the lower zone. To face this challenge, the operator has investigated simultaneous injection of miscible CO2 gas and polymer (SIMGAP) for reservoirs with an approximately 10-fold permeability contrast between the lower and upper zones and simultaneous injection of water and polymer (SIWAP) for reservoirs with a permeability contrast of 100-fold or greater between the lower and upper zones. These techniques rely on reducing mobility by polymer injection in the upper zone to provide a pressure barrier and reduce crossflow of the higher-mobility fluid injected into the lower zone.

PIT Simulation Model Setup

A single-well radial simulation model was built for PIT 1 to assess near-wellbore phenomena by minimizing in-situ velocity and shear-rate calculation errors compared with Cartesian coordinate grids. For interpretation of PIT 2, a mechanistic Cartesian 3D thermal black-oil simulation model was built by extracting a subsector from the last available static geomodel, preserving well architecture and grid resolution in the extracted subsector. The radial simulation model was found unsuitable for PIT 2 because the injector well presented a very high deviated section in the target reservoir, while the long string presented a long horizontal section. Therefore, the polymer injectivity and polymer bank propagation in the upper reservoir might not be represented properly using a vertical well.

Different local-grid-refinement (LGR) levels were implemented around the perforation length (upper zone), while the lower zone was in the root grid. The minimum cell radius in the model was determined to be 1.3 ft to avoid errors in well-index calculations considering the well-flow model. Thus, three LGR levels were applied.