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Collaborating Authors
Results
Water Management in Mature Oil Fields using Preformed Particle Gels
Goudarzi, Ali (1The University of Texas at Austin) | Zhang, Hao (2Missouri University of Science and Technology) | Varavei, Abdoljalil (1The University of Texas at Austin) | Hu, Yunpeng (2Missouri University of Science and Technology) | Delshad, Mojdeh (1The University of Texas at Austin) | Bai, Baojun (2Missouri University of Science and Technology) | Sepehrnoori, Kamy (1The University of Texas at Austin)
Abstract Excess water production is a major problem that leads to early well abandonment and unrecoverable hydrocarbon in mature oil fields. Gel treatments at the injection wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. A recent gel process uses the preformed particle gels (PPGs) to overcome distinct drawbacks inherent in in-situ gelation systems, i.e. lack of control on gelation time, uncertain gelling due to shear degradation, chromatographic fractionation or change of gel compositions, and dilution by formation water. This paper describes the results of PPG injection in both fracture and sandpack models where the experimental results were used to develop and validate mechanistic models to design and optimize the flowing gel injection for conformance control processes. Crucial properties gel such as in-situ rheology and swelling ratio in addition to oil recoveries were investigated. The water and oil permeability reduction factors were measured and modeled as a function of gel strength, rock permeability, and flow rate. The PPG transport models were successfully implemented in a reservoir simulator and validated against the laboratory experiments.
Abstract Upscaling of the geological model is an important component of any reservoir simulation work flow. This process introduces error due to averaging of sub-grid heterogeneity and introduces additional numerical diffusion. Upscaling errors are more severe when waterflooding is simulated in highly heterogeneous (channelized) porous media. When coarse grid blocks involve high and low permeability channels or layers, current upscaling techniques generally fail in representing the fine scale response accurately. In this work, the effect of heterogeneity on displacement efficiency in coarse-scale modeling is studied. The pore space of the fine-scale model is ranked based on the contribution to flow. Two levels of porosity are considered and classical dual-porosity models are used for coarse-scale flow simulation. A streamline index (SI), defined as the ratio of the streamline density to the time-of-flight, is used for storage categorization: An active pore volume represents the high flow paths in the porous system while a passive pore volume is considered as source/sink that feed into the major flow pathways. Several types of cut-off values, including the span of SI and local/global cut-offs, are discussed to determine the fraction of active pore volume in each coarse grid cell. The proposed technique is used to simulate waterflooding on two highly heterogeneous models. Displacement calculations are performed on the original fine grid and on a uniform coarse grid with global flow-based transmissibility upscaling. Simulation results from coarse single-porosity models (classical approach) and dual-porosity systems are then compared. Upscaling with dual-porosity flow modeling is demonstrated to provide for significant improvements in the accuracy of the coarse-scale simulation and arrives at a more accurate representation of the displacement performance.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Western Regional & AAPG Pacific Section Meeting, 2013 Joint Technical Conference held in Monterey, California, USA, 19 25 April 2013. 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 Historically a voidage replacement ratio (VRR) of 1 is assumed to be optimal for oil recovery regardless of whether recovery occurs from an unconventional heavy oil reservoir or a conventional oil reservoir. That is, it is assumed that of all scenarios, the most oil recovery occurs when the amount of fluids injected into the subsurface equals the amount produced. Recent work publications have analyzed both field and core-scale data to conclude that a VRR of 1 is suboptimal for certain viscous and heavy-oil reservoirs. In this work, we use numerical simulation to seek an understanding of the conditions under which a VRR of 1 is suboptimal. Models are core-size to enable better interpretation of mechanisms. We tested the sensitivity of the optimal VRR to the curvature of our relative permeability relationships (i.e., Corey exponent), the critical gas saturation, the three-phase flow model, potential chemistry of the oil, the statistics of permeability values, the connectivity of low and high permeability regions, and the reference scale at which results are compared.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (1.00)
Abstract The low salinity water injection method (LoSal) has become one of the important research topics in the oil industry because of its enormous possible advantages. The objective of this paper is to investigate the mechanism behind the LoSal effect on oil recovery through data matching. The UTCHEM simulator was used to match the cycles of the injected seawater and different dilutions of the latter for two recently published coreflooding experiments. The result from the history matching revealed that the wettability alteration mechanism is believed to be the main contributor to LoSal. Based on this finding, an analytical model for oil recovery predictions can be developed.
- Europe (1.00)
- Asia > Middle East > UAE (0.46)
- North America > United States > California (0.28)
- Geology > Mineral (0.47)
- Geology > Rock Type > Sedimentary Rock (0.31)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.36)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Abstract In this paper we use the concept of experimental design from the System Identification literature and introduce a novel methodology for more accurate characterization and monitoring of waterfloods using linear models. To improve the predictability of the low order linear models they must be trained with sufficiently informative data. To achieve this goal, the input (here injection rate) must contain sufficient variations (without exceeding the technical and operational limits) so that all the relevant dynamics of the system are excited and can be seen in the output (here production rate). In sum, a successful injection scheduling design boils down to introducing predetermined variations on top of the existing injection rates. We will discuss how to design these variations, specifically their amplitude, sampling time, experiment length, frequency of variations and signal type, using priori knowledge of the reservoir dynamics and the production constraints. Our proposed methodology can be applied to currently available linear modeling techniques such as CRM, FIR, subspace models, etc. This study shows that the prediction error of a model that has been trained with a proper injection scheduling design, in a multi injector multi producer oil field, can be reduced significantly regardless of the modeling technique.
- North America > United States > Texas > Fort Worth Basin > White Field (0.99)
- North America > United States > Arkansas > Smart Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Chemical Enhanced Oil Recovery (EOR) has regained its attention because of high oil price and the depletion of conventional oil reservoirs. This process is more complex than the primary and secondary recovery and requires detailed engineering design for a successful field-scale application. An alkaline/co-solvent/polymer (ACP) formulation was developed and corefloods were performed for a cost efficient alternative to alkaline/surfactant/polymer floods. Alkali reacts with acidic components of heavy oil (i.e. 170 cp in-situ viscosities) to form natural soap and significantly reduce the interfacial tension, which allows producing residual oil not contacted by waterflood or polymer flood alone. Polymer provides mobility control to drive chemical slug and oil bank. Co-solvent helps to improve the compatibility between in-situ soap and polymer and to reduce microemulsion viscosity. An impressive recovery of 70% of the waterflood residual oil saturation was achieved from an outcrop core where the remaining oil saturation after the ACP flood was reduced to only 13.5%. The results were promising with very low chemical utilization. UTCHEM reservoir simulator was used to model the coreflood experiment to obtain parameters for pilot scale simulations. Geological model was based on unconsolidated reservoir sand with multiple seven spot well patterns. However, facility capacity and field logistics, reservoir heterogeneity as well as mixing and dispersion effects might prevent the design followed in coreflood to be directly scaled for field implementation. Field-scale sensitivity simulations were conducted to optimize the design. The influence of chemical mass, slug size, polymer pre-flush, and injection rates on ultimate oil recovery was investigated. This research emphasizes the importance of small well spacing and good mobility control on recovery efficiency. The in-situ soap generated from alkali-naphthenic acid reaction not only mobilizes residual oil to increase oil recovery, but also enhances water relative permeability to increase injectivity. The paper discusses a cost effective chemical flooding design with an impressive oil recovery by adding relatively small solvent and polymer quantities to injected water. The potential for producing residual oil of the viscous oil is demonstrated in both the coreflood and pilot-scale simulations.
- Asia > China (0.93)
- North America > United States > Texas (0.46)
- Asia > Middle East > Oman (0.28)
- North America > United States > Wyoming > Kiehl Field (0.99)
- North America > United States > Wyoming > Big Muddy Field (0.99)
- Europe > France > Chateaurenard Field (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)