incremental oil recovery
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2021 ◽  
Vol 9 ◽  
Author(s):  
Jianhua Qin ◽  
Jing Zhang ◽  
Shijie Zhu ◽  
Yingwei Wang ◽  
Tao Wan

Field observations discern that the oil production rate decreases substantially and water cut increases rapidly with the increase of steam injection cycles. Compared with steam drive, the advantage of flue gas (also called multi-component thermal gas) co-injection with steam is that flue gas can increase the reservoir pressure and expand the heating chamber. In this paper, the flue gas generated by fuel burning in the field was injected with steam to improve heavy oil recovery. This technique was investigated in the large laboratory 3D model and implemented in the field as well. The huff-n-puff process efficiency by flue gas, steam, and flue gas–steam co-injection was compared in the experiments. The field practice also demonstrated that the addition of non-condensable gas in the steam huff-n-puff process recovered more oil than steam alone. The temperature profile in the wellbore with flue gas injection is higher than that with steam injection since the low thermal conductivity of N2 reduces the heat loss. With the increase of stimulation cycles, the incremental oil recovery by flue gas injection declines significantly.


2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Dawood Kamal ◽  
Najres Al-Mahmeed ◽  
Anfal Al Kharji ◽  
Hadeel Baroon ◽  
...  

Abstract The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.


Molecules ◽  
2021 ◽  
Vol 26 (24) ◽  
pp. 7468
Author(s):  
Xiaoqin Zhang ◽  
Bo Li ◽  
Feng Pan ◽  
Xin Su ◽  
Yujun Feng

Water-soluble polymers, mainly partially hydrolyzed polyacrylamide (HPAM), have been used in the enhanced oil recovery (EOR) process. However, the poor salt tolerance, weak thermal stability and unsatisfactory injectivity impede its use in low-permeability hostile oil reservoirs. Here, we examined the adaptivity of a thermoviscosifying polymer (TVP) in comparison with HPAM for chemical EOR under simulated conditions (45 °C, 4500 mg/L salinity containing 65 mg/L Ca2+ and Mg2+) of low-permeability oil reservoirs in Daqing Oilfield. The results show that the viscosity of the 0.1% TVP solution can reach 48 mPa·s, six times that of HPAM. After 90 days of thermal aging at 45 °C, the TVP solution had 71% viscosity retention, 18% higher than that of the HPAM solution. While both polymer solutions could smoothly propagate in porous media, with permeability of around 100 milliDarcy, TVP exhibited stronger mobility reduction and permeability reduction than HPAM. After 0.7 pore volume of 0.1% polymer solution was injected, TVP achieved an incremental oil recovery factor of 13.64% after water flooding, 3.54% higher than that of HPAM under identical conditions. All these results demonstrate that TVP has great potential to be used in low-permeability oil reservoirs for chemical EOR.


2021 ◽  
Author(s):  
G. Renouf ◽  
G. Bolton ◽  
P. Nakutnyy

Abstract Over the last 30 years, chemical flooding of oil reservoirs has been broadly adopted as a technique for enhanced and incremental oil recovery around the world. Western Canadian oil producers have embraced polymer flooding to recover heavy oil, but have applied other forms of chemical flooding more sparingly. This study examines 31 chemical floods - ASP, AP, SP, alkali, and nanosurfactant floods - from mostly heavy oil fields (20 heavy oil, 10 medium oil, and one light oil). The success of the chemical floods was related to over forty reservoir and operating parameters, including water quality. We also discuss the operational challenges common in western Canada. Chemical flooding projects were identified through searches of government documents. Production and injection data were gathered using Accumap software; and reservoir and operating parameters were gathered from government documents and literature. Incremental recovery was calculated by performing decline curve analysis of the waterflooding production. The incremental recovery was the difference between the actual production during chemical flooding, and the predicted production had waterflooding continued rather than shifting to chemical flooding. Multivariate analysis was used to determine the most important parameters to the success of the chemical floods. The incremental recoveries ranged from 0 to 22% of original oil-in-place (OOIP), or 0 to 44% of OOIP per pore volume. Twenty-three of the 31 floods improved their water-oil ratios (WOR) after the start of chemical flooding. Water quality was a significant issue to the success of the chemical floods, leading to problems that were not anticipated in the planning and development stages. Some case histories are discussed to better illustrate the best practices for chemical recovery of heavy and medium oils. Water sources, management, treatment and chemistry all pose significant challenges that are often not fully assessed before starting the chemical flood projects. The review highlights challenges common to chemical flooding of heavy oil, and discusses common effects experienced as a result of water and chemistry compromises.


Author(s):  
Hesham A. Abu Zaid ◽  
◽  
Sherif A. Akl ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
...  

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.


Author(s):  
Akinleye O. Sowunmi ◽  
Vincent E. Efeovbokhan ◽  
Oyinkepreye D. Orodu ◽  
Babalola A. Oni

AbstractGum arabic (GA) capacity as an enhanced oil recovery (EOR) agent is studied and compared to the commonly applied xanthan gum (XG). FTIR and TGA characterisation of these two polyelectrolytes and a rheology study by viscosity measurement was conducted on their polymeric and nano-polymeric solution at varying concentrations of the polymers and nanoparticles (NP). Coreflooding experiments were conducted based on a sequence of waterflooding and three slugs of increasing concentration of polymeric (and nano-polymeric) solutions to evaluate EOR performance. Results show similar rheology and oil recovery for 1.0 wt% GA and a 0.1 wt% XG polymeric solution. And the viscosity of GA tends to be Newtonian at a relatively high shear rate. The magnitude of incremental oil recovery of the first slug is independent of the GA concentration but significant for XG. However, the impact of nano-polymeric solution on oil recovery is higher than the polymeric solution. The increase in NP concentration played a vital role in oil recovery, thereby connoting the significance of IFT, contact angle, and its associated mechanisms for EOR. And FTIR affirms that the hydroxyl group in XG is less than GA, thus responsible for adsorption of GA compared to XG.


Author(s):  
M. Fouad Snosy ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
Helmy Sayyouh

AbstractWaterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.


2021 ◽  
Author(s):  
Hilario Martin Rodriguez ◽  
Yalda Barzin ◽  
Gregory James Walker ◽  
Markus Gruenwalder ◽  
Matias Fernandez-Badessich ◽  
...  

Abstract This study has double objectives: investigation of the main recovery mechanisms affecting the performance of the gas huff-n-puff (GHnP) process in a shale oil reservoir, and application of optimization techniques to modelling of the cyclic gas injection. A dual-permeability reservoir simulation model has been built to reproduce the performance of a single hydraulic fracture. The hydraulic fracture has the average geometry and properties of the well under analysis. A history match workflow has been run to obtain a simulation model fully representative of the studied well. An optimization workflow has been run to maximize the cumulative oil obtained during the GHnP process. The operational variables optimized are: duration of gas injection, soaking, and production, onset time of GHnP, injection gas flow rate, and number of cycles. This optimization workflow is launched twice using two different compositions for the injection gas: rich gas and pure methane. Additionally, the optimum case obtained previously with rich gas is simulated with a higher minimum bottom hole pressure (BHP) for both primary production and GHnP process. Moreover, some properties that could potentially explain the different recovery mechanisms were tracked and analyzed. Three different porosity systems have been considered in the model: fractures, matrix in the stimulated reservoir volume (SRV), and matrix in the non-SRV zone (virgin matrix). Each one with a different pressure profile, and thus with its corresponding recovery mechanisms, identified as below: Vaporization/Condensation (two-phase system) in the fractures.Miscibility (liquid single-phase) in the non-SRV matrix.Miscibility and/or Vaporization/Condensation in the SRV matrix: depending on the injection gas composition and the pressure profile along the SRV the mechanism may be clearly one of them or even both. Results of this simulation study suggest that for the optimized cases, incremental oil recovery is 24% when the gas injected is a rich gas, but it is only 2.4% when the gas injected is pure methane. A higher incremental oil recovery of 49% is obtained, when injecting rich gas and increasing the minimum BHP of the puff cycle above the saturation pressure. Injection of gas results in reduction of oil molecular weight, oil density and oil viscosity in the matrix, i.e., the oil gets lighter. This net decrease is more pronounced in the SRV than in the non-SRV region. The incremental oil recovery observed in the GHnP process is due to the mobilization of heavy components (not present in the injection gas composition) that otherwise would remain inside the reservoir. Due to the main characteristic of the shale reservoirs (nano-Darcy permeability), GHnP is not a displacement process. A key factor in success of the GHnP process is to improve the contact of the injected gas and the reservoir oil to increase the mixing and mass transfer. This study includes a review of different mechanisms, and specifically tracks the evolution of the properties that explain and justify the different identified mechanisms.


2021 ◽  
Author(s):  
Xiao Jin ◽  
Alhad Phatak ◽  
Aaron Sanders ◽  
Dawn Friesen ◽  
Ed Lewis ◽  
...  

Abstract In mixed- to oil-wet reservoirs characterized by intense natural fracturing where the dominant displacement mechanism is gravity drainage, surfactant injection can lead to a shift in wettability and incremental oil production. In some cases, oil can also re-imbibe back into the rock matrix after the oil saturation has been reduced upon initial exposure to surfactant, suggesting limited permanence in the wettability shift. The re-imbibition phenomenon is investigated in this paper utilizing Amott cells. Three cationic surfactants (C12-, C12-16-, C16-based) solutions with interfacial tensions (IFT) between 0.18 to 0.95 mN/m were pre-selected to be evaluated. Current applications of the C12- based surfactant in the Yates field is considered successful based on incremental oil recovery seen during the treatment. Silurian dolomite rock samples were flooded with Yates crude oil before being aged at 140 °F for 6 weeks. For the imbibition tests, synthetic brine was set as the external phase within the Amott cell and the recovery of oil was recorded periodically. After the imbibition tests ended, the rock samples were placed in an inverse Amott cell with the Yates oil as the external phase. Baseline tests were first conducted to show that without a surfactant in the oil or brine, no imbibition occurred. With a surfactant concentration of 3,000 ppm, oil recovery at the end of the imbibition tests varied from 34% to 64% of the original oil volume in the core sample. During the re-imbibition test, a large amount of oil was able to re-imbibe into the rock, displacing the brine. Most of the displacement occurred within the first two weeks. The net oil recovery, taken as the final volume of oil recovered in the imbibition test minus the final volume of oil re-imbibed into the rock, ranged from 0% to 18%. Given the possibility of surfactant dilution in field applications, another set of tests were conducted with 1,500 ppm. A reduction in oil recovery during imbibition was observed for both the C12- based surfactant and the C12-16- mixture. Partition coefficients were determined for each of the tested surfactants and the ion pair mechanism was used to explain the net oil recovery results. Lastly, the impact of rock permeability on re-imbibition was investigated. Results show increasing permeability may lead to a linear response in oil re-imbibition,therefore minimizing the permeability range when selecting rock samples may be necessary when conducting the re-imbibition test. The importance of oil re-imbibition is demonstrated in the experimental study and we make an argument for conducting both the imbibition and re-imbibition tests to better evaluate surfactant efficacy. The improved understanding of wettability alteration should lead to advancements in chemical enhanced oil recovery designs for field treatments.


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