scholarly journals Discerning In-Situ Performance of an Enhanced-Oil-Recovery Agent in the Midst of Geological Uncertainty: II. Fluvial-Deposit Reservoir

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1076-1091
Author(s):  
S. A. Fatemi ◽  
J.-D.. -D. Jansen ◽  
W. R. Rossen
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Geological Uncertainty ◽  
Polymer Injection ◽  
Fluvial Deposit ◽  
Water Breakthrough ◽  
Production Wells ◽  
Reservoir Description

Summary An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to be profitable (if possible), demonstrate oil recovery, verify the properties of the EOR agent in situ, and provide the information needed for scaleup to an economical process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in situ in the midst of geological uncertainty. We propose a numerical case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water/oil reservoir. The polymer is designed to have a viscosity of 20 cp in situ. We start with 100 realizations of the 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. For a population of reservoirs representing reduced geological uncertainty after 5 years of waterflooding, we select three groups of 10 realizations out of the initial 100, with similar water-breakthrough dates at the four production wells. We then simulate 5 years of polymer injection. We allow that the polymer process might fail in situ and viscosity could be 30% of that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity with the scatter caused by the geological uncertainty using a 95% confidence interval. Among the signals considered, polymer-breakthrough time, minimum oil cut, and rate of rise in injection pressure with polymer injection provide the most-reliable indications of whether a polymer viscosity was maintained in situ.

scholarly journals Effectiveness of In-Situ Microbial Enhanced Oil Recovery in a Post-Polymer Flooded Reservoir

2018 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Oil Production ◽  
Microbial Enhanced Oil Recovery ◽  
Observation Area ◽  
Production Wells ◽  
Light Components ◽  
Dominant Bacteria

This study investigated the effectiveness of In-situ microbial enhanced oil recovery (IMEOR) in a post-polymer flooded oil reservoir located in SaNan oilfield, Northeast China. Two rounds of injection of nutrient medium were intermittently injected into the producing block and then monitored. The main results showed that the dominant bacteria of 4 production wells, Thauera of Beta-proteobacteria, Pseudomonas and Acinetobacter of Gamma-proteobacteria were directional activation, which showed a consistent enhancement. The abundance of Methanosaeta and Methanolinea increased, and showed a regular alternation with an increase of oil production. It contributed to production of bio-gas, leading to increasing of the injection pressure from 11.3 MPa to 13.9 MPa before the experiment which increased by more than 2.0 MPa. The contents of CO2 and CH4 varied alternately, and the variation was consistent with the order of injection of each activator. H2 was detected in the reservoir associated with the gas in the observation area. A large amount of enriched bio-gas was dissolved into and mixed with crude oil, which brought increasing of the proportion of light components in the whole hydrocarbon of the recovered oil. The other effect was activated microbial metabolites productions formed bio-plugs, which benefits for improving of the absorption profile and the production profile. A total of 6,243 t of incremental oil production was achieved, and an oil recovery rate increased by 3.93% (OOIP) to the end of 2015. Our trial suggested that IMEOR can be implemented for effective enhancement of further oil recovery from polymer flooded oil reservoirs.

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

scholarly journals New insights into the mechanism of surfactant enhanced oil recovery: micellar solubilization and in-situ emulsification

2021 ◽  
Author(s):  
Xue-Zhi Zhao ◽  
Guang-Zhi Liao ◽  
Ling-Yan Gong ◽  
Huo-Xin Luan ◽  
Quan-Sheng Chen ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Micellar Solubilization

Innovations of Gas Lift in Prolific, Long-perforations, and Multilayered Wells, Case Study in Sudan

2016 ◽  
Author(s):  
Xueqing Tang ◽  
Lirong Dou ◽  
Ruifeng Wang ◽  
Jie Wang ◽  
Shengbao Wang ◽  
...  
Keyword(s):  
High Water ◽  
Water Breakthrough ◽  
Start Up ◽  
Production Wells ◽  
Decline Curves ◽  
High Water Cut ◽  
Water Cut ◽  
Gas Lift

ABSTRACT Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects: Extend end of tubing to the bottom of perforations for commingled production of oil and condensate gas zones, in order to utilize condensate gas producing from the lower zones for in-situ gas lift.Produce well stream from the casing annulus while injecting natural gas into the tubing.High-pressure nitrogen generated in-situ was used to kick off the dead wells, instead of installation of gas lift valves for unloading. After unloading process, the gas from compressors was injected down the tubing and back up the casing annulus.For previous high water-cut producers, prior to continuous gas lift, approximately 3.6 MMcf of nitrogen can be injected and soaked a couple of days for anti-water-coning.Two additional 10-in. flow lines were constructed to minimize the back pressure of surface facilities on wellhead. As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.

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