Successful Polymer Flooding of Low-Permeability, Oil-Wet, Carbonate Reservoir Cores

2014 ◽  
Author(s):  
Martin Vad Bennetzen ◽  
Syed Furqan H Gilani ◽  
Kristian Mogensen ◽  
Muhammad Ghozali ◽  
Noureddine Bounoua
Keyword(s):  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Low Permeability

Low-Salinity Polymer Flooding in a High-Temperature Low-Permeability Carbonate Reservoir in West Kuwait

2019 ◽  
Author(s):  
Mohammed Taha Al-Murayri ◽  
Dawood S. Kamal ◽  
Hessa M. Al-Sabah ◽  
Tareq AbdulSalam ◽  
Adnan Al-Shamali ◽  
...  
Keyword(s):  
High Temperature ◽  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Low Permeability ◽  
Low Salinity

A New Polymer Flooding Technology for Improving Low Permeability Carbonate Reservoir Recovery--From Lab Study to Pilot Test--Case Study from Oman

2019 ◽  
Author(s):  
Xingcai Wu ◽  
Yongli Wang ◽  
Ahmed Al Naabi ◽  
Hanbing Xu ◽  
Ibrahim Al Sinani ◽  
...  
Keyword(s):  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Low Permeability ◽  
Test Case ◽  
Pilot Test

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

2021 ◽  
Author(s):  
Nicolas Gaillard ◽  
Matthieu Olivaud ◽  
Alain Zaitoun ◽  
Mahmoud Ould-Metidji ◽  
Guillaume Dupuis ◽  
...  
Keyword(s):  
Middle East ◽  
Polymer Solutions ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Low Permeability ◽  
The Core ◽  
Reservoir Conditions ◽  
Carbonate Cores ◽  
The Impact ◽  
Mobility Reduction

Abstract Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.

Assessment of NPV Uncertainty on Heterogeneous Reservoirs during Polymer Flood

2013 ◽  
Vol 448-453 ◽  
pp. 4033-4037 ◽  
Author(s):  
Kyung Wan Yu ◽  
Byung In Choi ◽  
Kun Sang Lee
Keyword(s):  
Net Present Value ◽  
Water Saturation ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Low Permeability ◽  
Oil Viscosity ◽  
Permeability Model ◽  
Heterogeneous Reservoirs ◽  
Polymer Flood ◽  
Porosity And Permeability

This study shows net present value (NPV) distribution by considering uncertainties in porosity, oil viscosity, water saturation, and permeability for polymer flood with Monte Carlo simulation. For high and low average permeability conditions, differences of NPV between polymer flooding and water flooding have been investigated. According to results both average NPV and range of NPV distribution tend to increase with porosity and permeability in all cases. Although water saturation and oil viscosity affect NPV, they are not important parameters that conclude uncertainty of NPV under the conditions considered in this study. For high permeability model which has Dykstra-Parsons coefficient (DP) as 0.72 and porosity as 0.3088, Monte Carol simulations for polymer flood show that 50th percentile (P50) of NPV is 352.81 M$. If porosity is decreased from 0.3088 to 0.1912, the P50 is also decreased 63.8 %. The reduction of NPV during polymer flooding in low permeability reservoirs are almost 40 % higher than that of water flood. These differences come from polymer adsorption and permeability reduction that easily occurs in low permeability zone. The procedure has proven to be useful tool to generate probability distribution of NPV when polymer flood is selected as a tertiary flood process.

Oil Recovery in Low Permeability Sandstone Reservoirs Using Surfactant-Polymer Flooding

2015 ◽  
Author(s):  
C. Marliere ◽  
N. Wartenberg ◽  
M. Fleury ◽  
R. Tabary ◽  
C. Dalmazzone ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Polymer Flooding ◽  
Low Permeability ◽  
Sandstone Reservoirs

Study on a Self-Diverting Acid System for Well Stimulation Based on Novel Visco-Elastic Surfactant

2011 ◽  
Vol 287-290 ◽  
pp. 3120-3126 ◽  
Author(s):  
Fu Jian Zhou ◽  
Chun Ming Xiong ◽  
Yang Shi ◽  
Xian You Yang ◽  
Sheng Jiang Lian ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Carbonate Reservoir ◽  
Scanning System ◽  
Low Permeability ◽  
Acid System ◽  
Core Flooding ◽  
Well Stimulation ◽  
Core Permeability ◽  
Carbonate Formations ◽  
Oil Gas

Carbonate reservoir, widely distributed in china, is an important resource of oil and gas. Most of carbonate reservoir are very tight and need to be stimulated to increase the permeability for the flowing of oil/gas. Acid treatment is a kind of stimulation. However, the ordinary acid system cannot stimulate carbonate reservoir effectively because of the heterogeneity among formations. Based on a novel visco-elastic surfactant, this paper develops a self-diverting acid system (DCA) for carbonate formations. This system had been applied in the treatment of carbonate reservoirs successfully. Experiments studying the diverting mechanism had been conducted with HTHP Rheometer, parallel core flooding system and MRI Scanning system. The results indicate that: the viscosity of reacted acid can reach to 200 times higher than that of fresh acid. The injecting pressure of DCA is 20 times higher than that of ordinary acid (HCl) during the parallel core flooding experiment. MRI scanning images of the cores after acid flooding show that DCA can stimulate the cores with middle and low permeability more effectively. In middle and low permeability cores, the length of wormhole created by DCA is 4-8 times longer than that created by ordinary acid. At the same time, the relationship between flooding pressure and core permeability is also studied. This paper reveals the diverting mechanism of DCA through these experiments.

The Development Technology Policy of Secondary Oil Recovery in the Overpressure Carbonate Reservoir

2013 ◽  
Vol 680 ◽  
pp. 295-300
Author(s):  
Ye Fei Chen ◽  
Zi Fei Fan ◽  
Jun Ni ◽  
Yun Juan Li ◽  
Qing Ying Hou
Keyword(s):  
Oil Recovery ◽  
Technology Policy ◽  
Water Injection ◽  
Carbonate Reservoir ◽  
Low Permeability ◽  
Development Mode ◽  
Engineering Research ◽  
Well Spacing ◽  
Development Technology ◽  
Secondary Oil Recovery

Kenkiyak oilfield in kazakstan is a low porosity, extremely low permeability and overpressure carbonate reservoir. There are different reservoir and fracture characteristics in different region. The formation pressure decline seriously and water cannot be injected into the low permeability zone. Referring to the domestic and oversea research achievement, integrating regional geologic characteristics, numerical simulation results and reservoir engineering research results, we optimize a series of the development technology policy, including the reasonable gas and water injection modes and injection opportunity, the suitable well patterns and well spacing. Meanwhile, the development mode of energy supplement in the extremely low permeability and overpressure reservoir is explored.

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