scholarly journals Oil production and reservoir damage during miscible CO2 injection

2020 ◽  
Vol 39 (1) ◽  
pp. 22-28 ◽  
Author(s):  
Qian Wang ◽  
Piroska Lorinczi ◽  
Paul W. J. Glover
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Control Measures ◽  
Co2 Injection ◽  
Formation Damage ◽  
Core Flooding ◽  
Asphaltene Precipitation ◽  
Pore Throat ◽  
Oil Distribution ◽  
Inorganic Precipitation

The blockage and alteration of wettability in reservoirs caused by asphaltene deposits are problems that contribute to poor oil recovery performance during carbon dioxide (CO2) injection. Oil production and reservoir damage are both controlled by macroscopic interlayer heterogeneity and microscopic pore-throat structure and may be optimized by the choice of flooding method. In this work, the residual oil distribution and the permeability decline caused by organic and inorganic precipitation after miscible CO2 flooding and water-alternating-CO2 (CO2-WAG) flooding have been studied by carrying out core-flooding experiments on a model heterogeneous three-layer reservoir. For CO2, flooding experimental results indicate that the low-permeability layers retain a large oil production potential even in the late stages of production, while the permeability decline due to formation damage is larger in the high-permeability layer. We found that CO2-WAG can reduce the influence of heterogeneity on the oil production, but it results in more serious reservoir damage, with permeability decline caused by CO2–brine–rock interactions becoming significant. In addition, miscible CO2 flooding has been carried out for rocks with similar permeabilities but different wettabilities and different pore-throat microstructures in order to study the effects of wettability and pore-throat microstructure on formation damage. Reservoir rocks with smaller pore-throat sizes and more heterogeneous pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding lower oil recovery and greater decreases in permeability. However, it was found that the degree of water wetness for cores with larger, more connected pore-throat microstructures became weaker due to asphaltene precipitation to pore surfaces. Decreasing the degree of water wetness was found to be exacerbated by increases in the sweep volume of injected CO2 that arise from cores with larger and better connected pore throats. Erosion of water wetness is a disadvantage for enhanced oil recovery operations as asphaltene precipitation prevention and control measures become more necessary.

Effects of pore-throat structure on reservoir blockage and wettability alteration during CO2 injection

2020 ◽  
Author(s):  
Qian Wang ◽  
Paul Glover ◽  
Piroska Lorinczi
Keyword(s):  
Fluid Flow ◽  
Pore Size ◽  
Oil Recovery ◽  
Fractal Theory ◽  
Carbon Capture And Storage ◽  
Wettability Alteration ◽  
Co2 Injection ◽  
Asphaltene Precipitation ◽  
Pore Throat ◽  
Pore Size Distributions

<p>Injection of CO<sub>2</sub> into subsurface reservoirs occurs during Enhanced Oil Recovery (EOR) and also during Carbon Capture and Storage (CCS) operations. During CO<sub>2</sub> injection, the efficacy and distribution of fluid flow in sandstone reservoirs is controlled by the pore-throat microstructure of the rock. Furthermore, CO<sub>2</sub> injection promotes asphaltene precipitation on the pore surface and can also affect fluid flow in the pore throats, decreasing the permeability and altering reservoir wettability. In this work, miscible and immiscible CO<sub>2</sub> flooding experiments under reservoir conditions (up to 70℃, 18 MPa) have been carried out on four samples with very similar permeabilities but different pore-throat structures in order to study the effects of pore-throat microstructure on formation damage. The features of pore-throat structure were evaluated by fractal theory, based on pore size distributions and rate-controlled porosimetry (RCP) mercury intrusion curves. Reservoir rocks with smaller pore throat sizes and more heterogeneous and poorer pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding 15-20% lower oil recovery and 4-7% greater decreases in permeability than that of rocks with homogeneous and better pore-throat microstructure. However, the water-wettability index of cores with larger and more connected pore-throat microstructures was found to drop by an extra 15-25% than heterogeneous core due to more asphaltene precipitation caused by the larger sweep volume of injected CO<sub>2</sub> they consequently experienced, which is a disadvantage for EOR. In addition, immiscible flooding exacerbates the differences from 4-7% to 8-15% in permeability decline of the rocks with different pore-throat structures. Miscible flooding leads to more asphaltenes being precipitated from the crude oil, triggering in average an extra 11% change in wettability in comparison to immiscible flooding.</p><p><strong> </strong></p><p><strong>Keywords:</strong> CO<sub>2</sub> flooding, asphaltene precipitation, pore size distribution, pore-throat microstructure, reservoir blockage, wettability alteration</p>

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

A New Approach of Pressure Profile and Oil Recovery During Dual and Single Core Flooding of Seawater and CO2 Injection Process for Carbonate Reservoir

2016 ◽  
Author(s):  
Xianmin Zhou ◽  
Fawaz AlOtaibi ◽  
Sunil Kokal ◽  
Almohannad Alhashboul ◽  
Jassi Al-Qahtani
Keyword(s):  
Oil Recovery ◽  
Pressure Profile ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Core Flooding ◽  
New Approach ◽  
Injection Process

Modeling Formation Damage by Asphaltene Deposition During Primary Oil Recovery

2005 ◽  
Vol 127 (4) ◽  
pp. 310-317 ◽  
Author(s):  
Shaojun Wang ◽  
Faruk Civan
Keyword(s):  
Experimental Data ◽  
Mathematical Model ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Formation Damage ◽  
Asphaltene Precipitation ◽  
Vertical Wells ◽  
Core Flow ◽  
Asphaltene Deposition

Asphaltene precipitation and deposition during primary oil recovery and resulting reservoir formation damage are described by a phenomenological mathematical model. This model is applied using experimental data from laboratory core flow tests. The effect of asphaltene deposition on porosity, permeability, and the productivity of vertical wells in asphaltenic-oil reservoirs are investigated by simulation.

Asphaltene precipitation and deposition during CO2 injection in nano shale pore structure and its impact on oil recovery

Fuel ◽  
2019 ◽  
Vol 237 ◽  
pp. 1029-1039 ◽  
Author(s):  
Sherif Fakher ◽  
Abdulmohsin Imqam
Keyword(s):  
Pore Structure ◽  
Oil Recovery ◽  
Co2 Injection ◽  
Asphaltene Precipitation

Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years

2021 ◽  
Author(s):  
Martin Shumway ◽  
Ryan McGonagle ◽  
Anthony Nerris ◽  
Janaina I.S. Aguiar ◽  
Amir Mahmoudkhani ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Cost Effective ◽  
Field Trials ◽  
Lessons Learned ◽  
Formation Damage ◽  
Well Stimulation ◽  
Tight Formations ◽  
History Of ◽  
Organic Deposits

Abstract Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.

Low-Cost Development Plan Optimization for a Polish Oil Field

2021 ◽  
Author(s):  
Daniel Podsobinski ◽  
Roman Madatov ◽  
Bartlomiej Kawecki ◽  
Grzegorz Paliborek ◽  
Piotr Wójcik ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Capital Expenditure ◽  
Oil Production ◽  
Oil Field ◽  
Oil Fields ◽  
Development Plan ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Development Scenarios ◽  
Injection Water

Abstract In Poland there are approximately 60 oil fields located in different geological structures. Most of these fields have been producing for several years to several dozen years, and now require redefining of the development plan by utilizing an improved oil recovery (IOR) or enhanced oil recovery (EOR) method to achieve a higher oil recovery factor. Here we present the redevelopment plan for the Polish Main Dolomite oil field, that aimed to optimize and maximize the oil recovery factor. Considering all available geological and reservoir data, both a static and dynamic model were built and calibrated for three separate reservoirs connected to the same production facility. Then the comprehensive study was performed where different development scenarios was considered and tested using reservoir numerical simulation. The proposed redevelopment scenarios included excessive gas reinjection to the main reservoir, additional high-nitrogen (N2) gas injection from a nearby gas reservoir (87% of N2), carbon dioxide (CO2) injection, water injection, polymer injection, water-alternating-gas (WAG), well stimulation, and a combination of these methods. Development plans assumes also drilling new injection and production wells and converting existing producers to gas or water injectors. The key component in development scenarios was to arrest the pressure decline from the main field and decrease the gas/oil ratio (GOR). An additional challenge was to implement in the simulation model all key assumptions behind various development scenarios, while also taking into account specific facility constraints and simultaneously handling separate reservoirs that are connected to the same facility, and hence affecting each other. From numerous scenarios, the scenario that requires the least number of new wells was selected and further optimized. It considers the drilling of only one new producer, one new water injector, and conversion of some currently producing wells to gas and water injectors. The location of the proposed well and the amount of injection fluids was optimized to achieve the highest oil recovery factor and to postpone gas and water breakthrough as much as possible. The optimized case that assumes low investments is expected to improve incremental oil production by 90% over No Further Actions Scenario. However, the study suggests the potential of more than tripling incremental oil production under a scenario with considerably higher expenditures. The improved case assumes drilling one more producer, four new water injectors, and injection of three times more water. The presented field optimization example highlights that in many existing Polish oil fields there is still a potential to reach higher oil recovery without considerable expenditures. However, to obtain more significant oil recovery improvement, higher capital expenditure is necessary. To facilitate the selection of the best development scenario, a detailed economic and risk analysis needs to be conducted.

Improving Oil Recovery Through Fracture Injection and Production of Multiple Fractured Horizontal Wells

2020 ◽  
Vol 142 (5) ◽  
Author(s):  
Youwei He ◽  
Shiqing Cheng ◽  
Zhe Sun ◽  
Zhi Chai ◽  
Zhenhua Rui
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Horizontal Wells ◽  
Co2 Injection ◽  
Production Rates ◽  
Well Production ◽  
Well Completion ◽  
Tight Formations ◽  
Fractured Horizontal Wells ◽  
The Impact

Abstract Well production rates decline quickly in the tight reservoirs, and enhanced oil recovery (EOR) is needed to increase productivity. Conventional flooding from adjacent wells is inefficient in the tight formations, and Huff-n-Puff also fails to achieve the expected productivity. This paper investigates the feasibility of the inter-fracture injection and production (IFIP) method to increase oil production rates of horizontal wells. Three multi-fractured horizontal wells (MFHWs) are included in a cluster well. The fractures with even and odd indexes are assigned to be injection fractures (IFs) and recovery fractures (RFs). The injection/production schedule includes synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). The production performances of three MFHWs are compared by using four different recovery approaches based on numerical simulation. Although the number of RFs is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than depletion and CO2 Huff-n-Puff. The sensitivity analysis is performed to investigate the impact of parameters on IFIP. The spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect oil production significantly, followed by the length of RFs, well spacing among MFHWs, and the length of IFs. The suggested well completion scheme for the IFIP methods is presented. This work discusses the ability of the IFIP method in enhancing the oil production of MFHWs.

scholarly journals Enhanced Tight Oil Recovery by Volume Fracturing in Chang 7 Reservoir: Experimental Study and Field Practice

Energies ◽  
2019 ◽  
Vol 12 (12) ◽  
pp. 2419
Author(s):  
Long Yu ◽  
Jinjie Wang ◽  
Chong Wang ◽  
Daixin Chen
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Field Application ◽  
Tight Oil ◽  
Core Flooding ◽  
Hydrocarbon Source Rock ◽  
Reservoir Stimulation ◽  
Field Practice ◽  
Volume Fracturing ◽  
Pilot Tests

The Chang 7 reservoir in Changqing oilfield is rich in tight oil. However, due to the low formation permeability, it is very difficult to obtain economical oil production without stimulation treatments. Volume fracturing seems to be a more efficient tight oil recovery enhancement (EOR) method in Chang 7 pilot tests compared with conventional hydraulic fracturing. In this study, Chang 7 tight oil reservoir was first characterized by its geological property, hydrocarbon source rock distribution, and formation physiochemical property. Tight core flooding tests were then conducted to experimentally investigate the EOR ability of the volume fracturing technique. The field-scale practice was also demonstrated and analyzed. The results show that Chang 7 reservoir is favorable for the generation of a large amount of tight oil. Fractures created in tight cores can significantly improve the fluid flow conductivity and enhance the imbibition of displacing water, resulting in a greater tight oil recovery increment. Volume fracturing is an effective way to generate a larger number of fractures. Field application indicates that volume fracturing treatment can form a much greater reservoir stimulation volume. Daily oil production in the volume-fracturing-treated wells can be more than twice as high as that in the conventional-fracturing-treated wells.

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