SOME SPECIFIC FEATURES OF THE IMPACT OF GEOLOGICAL-TECHNICAL MEASURES ON THE EFFICIENCY OF OIL RECOVERY ENHANCEMENT BY USING A NON-STATIONARY (CYCLIC) WATER-FLOODING

2018 ◽  
pp. 26-34
Author(s):  
M.R. Dulkarnaev ◽  
◽  
N.P. Zakharova ◽  
N.A. Demyanenko ◽  
E.N. Malshakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Flooding ◽  
The Impact ◽  
Technical Measures

Optimization of Smart Water Chemical Composition for Carbonate Rocks Through Comparison of Active Cations Performance

2017 ◽  
Vol 139 (6) ◽  
Author(s):  
Malek Jalilian ◽  
Peyman Pourafshary ◽  
Behnam Sedaee Sola ◽  
Mosayyeb Kamari
Keyword(s):  
Chemical Composition ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Low Cost ◽  
Recovery Phase ◽  
Ion Concentration ◽  
Water Flooding ◽  
Core Flooding ◽  
Smart Water ◽  
The Impact

Designing smart water (SW) by optimizing the chemical composition of injected brine is a promising low-cost technique that has been developed for both sandstone and carbonate reservoirs for several decades. In this study, the impact of SW flooding during tertiary oil recovery phase was investigated by core flooding analysis of pure limestone carbonate rocks. Increasing the sulfate ion concentration by using CaSO4 and MgSO4 of NaCl concentration and finally reducing the total salinity were the main manipulations performed to optimize SW. The main objective of this research is to compare active cations including Ca2+ and Mg2+ in the presence of sulfate ions (SO42−) with regard to their efficiency in the enhancement of oil production during SW flooding of carbonate cores. The results revealed a 14.5% increase in the recovery factor by CaSO4 proving its greater effectiveness compared to MgSO4, which led to an 11.5% production enhancement. It was also realized that low-salinity water flooding (LSWF) did not lead to a significant positive effect as it contributed less than 2% in the tertiary stage.

scholarly journals Experimental study of in-situ W/O emulsification during the injection of MgSO4 and Na2CO3 solutions in a glass micromodel

2020 ◽  
Vol 75 ◽  
pp. 87
Author(s):  
Sepideh Palizdan ◽  
Hossein Doryani ◽  
Masoud Riazi ◽  
Mohammad Reza Malayeri
Keyword(s):  
Experimental Study ◽  
Flow Rate ◽  
Oil Recovery ◽  
Deionized Water ◽  
Water Flooding ◽  
Flow Rates ◽  
Glass Micromodel ◽  
The Impact ◽  
Emulsification Process

In-situ emulsification of injected brines of various types is gaining increased attention for the purpose of enhanced oil recovery. The present experimental study aims at evaluating the impact of injecting various solutions of Na2CO3 and MgSO4 at different flow rates resembling those in the reservoir and near wellbore using a glass micromodel with different permeability regions. Emulsification process was visualized through the injection of deionized water and different brines at different flow rates. The experimental results showed that the extent of emulsions produced in the vicinity of the micromodel exit was profoundly higher than those at the entrance of the micromodel. The injection of Na2CO3 brine after deionized water caused the impact of emulsification process more efficiently for attaining higher oil recovery than that for the MgSO4 brine. For instance, the injection of MgSO4 solution after water flooding increased oil recovery only up to 1%, while the equivalent figure for Na2CO3 was 28%. It was also found that lower flow rate of injection would cause the displacement front to be broadened since the injected fluid had more time to interact with the oil phase. Finally, lower injection flow rate reduced the viscous force of the displacing fluid which led to lesser occurrence of viscous fingering phenomenon.

scholarly journals An Experimental Investigation the Optimum of Salinity and Ph of Sea-Water to Improve Oil Recovery from Sandstone Reservoir as A Secondary Recovery Process

2020 ◽  
Vol 1 (2) ◽  
pp. 83
Author(s):  
Madi Abdullah Naser ◽  
Mohammed A Samba ◽  
Yiqiang Li
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Recovery Process ◽  
Water Flooding ◽  
Core Flooding ◽  
Low Salinity ◽  
Seawater Salinity ◽  
Secondary Recovery ◽  
Two Parameters ◽  
The Impact

Laboratory tests and field applications shows that the salinity of water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity water flooding studies. However, there are few quantitative studies on seawater composition change and it impact on increasing or improving oil recovery.  This study was conducted to investigate only two parameters of the seawater (Salinity and pH) to check their impact on oil recovery, and what is the optimum amount of salinity and ph that we can use to get the maximum oil recovery.  Several core flooding experiments were conducted using sandstone by inject seawater (high, low salinity and different pH). The results of this study has been shown that the oil recovery increases as the injected water salinity down to 6500 ppm and when the pH is around 7. This increase has been found to be supported by an increase in the permeability. We also noticed that the impact of ph on oil recovery is low when the pH is less than 7.

scholarly journals Mechanisms of Microscopic Displacement During Enhanced Oil Recovery in Mixed-Wet Rocks Revealed Using Direct Numerical Simulation

2019 ◽  
Vol 130 (3) ◽  
pp. 731-749 ◽  
Author(s):  
Takashi Akai ◽  
Amer M. Alhammadi ◽  
Martin J. Blunt ◽  
Branko Bijeljic
Keyword(s):  
Numerical Simulation ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Surfactant Flooding ◽  
Displacement Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
The Impact

Abstract We demonstrate how to use numerical simulation models directly on micro-CT images to understand the impact of several enhanced oil recovery (EOR) methods on microscopic displacement efficiency. To describe the physics with high-fidelity, we calibrate the model to match a water-flooding experiment conducted on the same rock sample (Akai et al. in Transp Porous Media 127(2):393–414, 2019. 10.1007/s11242-018-1198-8). First we show comparisons of water-flooding processes between the experiment and simulation, focusing on the characteristics of remaining oil after water-flooding in a mixed-wet state. In both the experiment and simulation, oil is mainly present as thin oil layers confined to pore walls. Then, taking this calibrated simulation model as a base case, we examine the application of three EOR processes: low salinity water-flooding, surfactant flooding and polymer flooding. In low salinity water-flooding, the increase in oil recovery was caused by displacement of oil from the centers of pores without leaving oil layers behind. Surfactant flooding gave the best improvement in the recovery factor of 16% by reducing the amount of oil trapped by capillary forces. Polymer flooding indicated improvement in microscopic sweep efficiency at a higher capillary number, while it did not show an improvement at a low capillary number. Overall, this work quantifies the impact of different EOR processes on local displacement efficiency and establishes a workflow based on combining experiment and modeling to design optimal recovery processes.

Heavy Oil Distribution and its Influence on Remaining Oil Distribution of G6 Block in Jinhu Depression

2014 ◽  
Vol 556-562 ◽  
pp. 937-939
Author(s):  
Xue Li ◽  
Jing Rui Xu ◽  
Jin Liang Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Flooding ◽  
Dynamic Resistance ◽  
Reservoir Properties ◽  
Oil Distribution ◽  
Geological Conditions ◽  
Remaining Oil ◽  
Remaining Oil Distribution ◽  
The Impact

Heavy oil, with the characteristics of high viscosity and large density, is the most important component of petroleum hydrocarbon energy. In reservoir exploration, its dynamic resistance not only reduces driven efficiency, but also brings much more exploration difficulty, so it is not feasible to exploit heavy oil with conventional methods. Previous studies have carried heavy oil research , but few have attempted to examine the impact of heavy oil on reservoir properties .In this paper, a detailed analysis of heavy oil distribution and remaining oil distribution of G6 block is performed. The conclusion are drawn: the local water flooding and local remaining oil selectively accumulation are caused by heavy oil through reducing water flooding efficiency; As to heavy oil recovery, appropriate exploration should be selected to reduce viscosity of heavy oil according to different geological conditions.

60 Years Field Performance Data-Driven Analytics to Generate Updated Waterflood Field Development Plan in a North Kuwait Giant Carbonate Reservoir

2021 ◽  
Author(s):  
Basel AL-Otaibi ◽  
Issa Abu Shiekah ◽  
Manish Kumar Jha ◽  
Gerbert de Bruijn ◽  
Peter Male ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Horizontal Wells ◽  
Carbonate Reservoir ◽  
Development Plan ◽  
Data Driven ◽  
Water Flooding ◽  
Field Development ◽  
The Impact

Abstract After 40 years of depletion drive, a mature, giant and multi-layer carbonate reservoir is developed through waterflooding. Oil production, sustained through infill drilling and new development patterns, is often associated with increasingly higher water production compared to earlier development phases. A field re-development plan has been established to alleviate the impact of reservoir heterogeneities on oil recovery, driven by the analysis of the historical performance of production and injection of a range of well types. The field is developed through historical opportunistic development concepts utilizing evolving technology trends. Therefore, the field has initially wide spacing vertical waterflooding patterns followed by horizontal wells, subjected to seawater or produced water injection, applying a range of wells placement or completion technologies and different water injection operating strategies. Systematic categorization, grouping and analyzing of a rich data set of wells performance have been complemented and integrated with insights from coarse full field and conceptual sector dynamic modeling activities. This workflow efficiently paved the way to optimize the field development aiming for increased oil recovery and cost saving opportunities. Integrated analysis of evolving historical development decisions revealed and ranked the primary subsurface and operational drivers behind the limited sweep efficiency and increased watercut. This helped mapping the impact of fundamental subsurface attributes from well placement, completion, or water injection strategies. Excellent vertical wells performance during the primary depletion and the early stage of water flooding was slowly outperformed by a more sustainable horizontal well production and injection strategy. This is consistent with a conceptual model in which the reservoir is dominated by extensive high conductive features that contributed in the early life of the field to good oil production before becoming the primary source of premature water breakthrough after a limited fraction of pore volume water was injected. The next level of analysis provided actual field evidence to support informed decisions to optimize the front runner horizontal wells development concept to cover wells length, orientation, vertical placement in the stratigraphy, spacing, pattern strategy and completion design. The findings enabled delivering updated field development plan covering the field life cycle to sustain and increase field oil production through adding ~ 200 additional wells and introducing more structured water flooding patterns in addition to establishing improved wells reservoir management practices. This integrated study manifests the power, efficiency and value from data driven analysis to capture lessons learned from evolving wells and development concepts applied in a complex brown field over six decades. The workflow enabled the delivery of an updated field development plan and production forecasts within a year through utilizing data analytics to compensate for the recognized limitations of subsurface models in addition to providing input to steer the more time-consuming modeling activities.

scholarly journals The effect of CO2-enriched water salinity on enhancing oil recovery and its potential formation damage: an experimental study on shaly sandstone reservoirs

2020 ◽  
Vol 10 (8) ◽  
pp. 3791-3802
Author(s):  
Ehsan Yazdani Sadati ◽  
Eghbal Sahraei ◽  
Milad Rahnema ◽  
Sohail Rashidi Aghdam ◽  
Mahsheed Reyhani
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Water Flooding ◽  
Experimental Investigations ◽  
Formation Damage ◽  
Permeability Reduction ◽  
Recovery Method ◽  
Potential Formation ◽  
Carbonated Water ◽  
The Impact

Abstract Many experimental investigations on carbonated water injection (CWI) have shown an increase in oil recovery which CWI is defined as the process of injecting CO2-saturated water in oil reservoirs as a displacing fluid. In every enhanced oil recovery method, the potential formation damage of the injected fluid is considered. This is due to the fact that the injection of incompatible fluids often causes clay swelling and fines migration and thus impairs the formation permeability. Permeability reduction by clay particles mostly depends on its distribution which can be pore lining, pore bridging, dispersed or combination of these causing pore blocking or pore-throat diameter reduction. Besides, fine migration is considered as an important mechanism of recovery improvement during injection of low-salinity water in sandstone oil reservoirs. The present paper investigates the impact of injection of carbonated water and brines with the different salt concentrations on oil recovery and formation damage focusing on permeability variation. The investigation has been done on 12 relatively homogeneous clay-containing sandstone cores, while the compositions of the injection water were varied from 40,000 to 1000 ppm, at 176° F and 2000 psi. The amount of recovery improvement and permeability drop recorded in all tests and the fine effluent of two experiments were analysed using XRD, one for CWI and one for WF (water flooding). In all salinities, CWI has shown more oil recovery improvement than conventional water. CWI of 40,000 ppm showed the minimum permeability reduction of 6 percent, while the highest permeability was obtained by injection of water with 1000 ppm. Maximum ultimate oil recoveries of 61.2% and 42% were achieved by 1000 ppm both for CWI and WF, respectively. In comparison with brine injection, CWI resulted in more permeability drop in salinity above critical salt concentration (CSC), while below CSC, WF has caused more formation damage than CWI. Experimental results also showed that fine migration was the main reason behind formation damage. It was also revealed that permeability was significantly reduced due to fine production in the effluent.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

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