Injection of Nitrogen Foam for Improved Oil Recovery in Viscous Oil Reservoirs Offshore Bohai Bay China

2016 ◽  
Author(s):  
Y. M. Liu ◽  
L. Zhang ◽  
S. R. Ren ◽  
B. Ren ◽  
S. T. Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Bohai Bay ◽  
Improved Oil Recovery ◽  
Viscous Oil ◽  
Nitrogen Foam

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Yaoze Cheng ◽  
Yin Zhang ◽  
Abhijit Dandekar ◽  
Jiawei Li
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Viscosity Reduction ◽  
Displacement Efficiency ◽  
Natural Sand ◽  
Ζ Potential ◽  
Low Salinity ◽  
Viscous Oil ◽  
Reservoir Conditions ◽  
Salinity Water

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

Effect of Chlorite Clay-Mineral Dissolution on the Improved Oil Recovery From Sandstone Rocks During Diethylenetriaminepentaacetic Acid Chelating-Agent Flooding

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1880-1898 ◽  
Author(s):  
Mohamed Ahmed El-Din Mahmoud
Keyword(s):  
Contact Angle ◽  
Surface Charge ◽  
Clay Minerals ◽  
Oil Recovery ◽  
Chelating Agent ◽  
Oil Reservoirs ◽  
Diethylenetriaminepentaacetic Acid ◽  
Improved Oil Recovery ◽  
Angle Measurements ◽  
Contact Angle Measurements

Summary Sandstone oil reservoirs consist of different clay minerals, such as kaolinite, illite, and chlorite. While these clay minerals can highly affect oil recovery from sandstone oil reservoirs, no attention has been given to investigating the effects of clay minerals during such oil recovery, and no solution has been introduced to alleviate the effects. In this study, and for the first time, the effect of chlorite clay-mineral content on the improved oil recovery (IOR) from different sandstone rock samples was investigated. A new solution was proposed to eliminate the effect of chlorite on the oil recovery from sandstone rocks. Different sandstone cores were used, such as Berea (BSS), Bandera (BND), Kentucky (KSS), and Scioto (SCS) sandstone rocks with different clay minerals. ζ-potential measurements were used to investigate the surface charge of the different clays and different sandstone rocks with different fluids. Fluids such as seawater (SW), low-salinity water (LSW), fresh water, and chelating agents were used. Diethylenetriaminepentaacetic acid (DTPA) chelating agent was introduced to mitigate the chlorite effect on oil recovery from sandstone rocks. The wettability was evaluated using contact-angle measurements and the Amott test for different solutions and different rocks in the presence of actual crude oil. Coreflooding experiments were conducted using these fluids with different sandstone rocks to identify the effect of chlorite on the oil recovery. Coreflooding experiments showed that sandstone cores with high chlorite content yielded the lowest oil recovery when SW and LSW were used. The effect of chlorite on the oil recovery from the two sandstone rocks was minimized with 3 wt% DTPA chelating agent. More oil was recovered in the case of DTPA because of the iron chelation from chlorite. ζ-potential showed that sandstone with high chlorite content has a surface charge close to zero in the case of SW and fresh water. In addition, contact-angle measurements showed that samples with high chlorite content have less water-wetness, which will reduce oil recovery. Contact-angle measurements on chlorite sheets showed that chlorite is oil-wet compared with mica at the same conditions. The addition of high-pH DTPA chelating agent sequestered the iron from the chlorite clay minerals and changed the surface charge to very high negative value, and the contact angle confirmed that the rock changed to water-wet after adding the chelating agent. The Amott index showed that adding DTPA increased the water-wetness for SCS that contains 4 wt% chlorite.

Sweep Efficiency of Miscible Floods in a High-Pressure Quarter-Five-Spot Model

SPE Journal ◽  
2008 ◽  
Vol 13 (04) ◽  
pp. 432-439 ◽  
Author(s):  
Edward J. Lewis ◽  
Eric Dao ◽  
Kishore K. Mohanty
Keyword(s):  
High Pressure ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Recovery Efficiency ◽  
Sweep Efficiency ◽  
Viscous Oil ◽  
Spot Model ◽  
Reservoir Conditions ◽  
Wag Injection ◽  
Medium Viscosity

Summary Evaluation and improvement of sweep efficiency are important for miscible displacement of medium-viscosity oils. A high-pressure quarter-five-spot cell was used to conduct multicontact miscible (MCM) water-alternating-gas (WAG) displacements at reservoir conditions. A dead reservoir oil (78 cp) was displaced by ethane. The minimum miscibility pressure (MMP) for ethane with the reservoir oil is approximately 4.14 MPa (600 psi). Gasflood followed by waterflood improves the oil recovery over waterflood alone in the quarter five-spot. As the pressure decreases, the gasflood oil recovery increases slightly in the pressure range of 4.550-9.514 MPa (660-1,380 psi) for this undersaturated viscous oil. WAG improves the sweep efficiency and oil recovery in the quarter five-spot over the continuous gas injection. WAG injection slows down gas breakthrough. A decrease in the solvent amount lowers the oil recovery in WAG floods, but significantly more oil can be recovered with just 0.1 pore volume (PV) solvent (and water) injection than with waterflood alone. Use of a horizontal production well lowers the sweep efficiency over the vertical production well during WAG injection. Sweep efficiency is higher for the nine-spot pattern than for the five-spot pattern during gas injection. Sweep efficiency during WAG injection increases with the WAG ratio in the five-spot model. Introduction As the light-oil reservoirs get depleted, there is increasing interest in producing more-viscous-oil reservoirs. Thermal techniques are appropriate for heavy-oil reservoirs. But gasflooding can play an important role in medium-viscosity-oil (30-300 cp) reservoirs and is the subject of this paper. Roughly 20 billion to 25 billion bbl of medium-weight- to heavy-weight-oil deposits are estimated in the North Slope of Alaska. Approximately 10 billion to 12 billion bbl exist in West Sak/Schrader Bluff formation alone (McGuire et al. 2005). Miscible gasflooding has been proved to be a cost-effective enhanced oil recovery technique. There are approximately 80 gasflooding projects (CO2, flue gas, and hydrocarbon gas) in the US and approximately 300,000 B/D is produced from gasflooding, mostly from light-oil reservoirs (Moritis 2004). The recovery efficiency [10-20% of the original oil in place (OOIP)] and solvent use (3-12 Mcf/bbl) need to be improved. The application of miscible and immiscible gasflooding needs to be extended to medium-viscosity-oil reservoirs. McGuire et al. (2005) have proposed an immiscible WAG flooding process, called viscosity-reduction WAG, for North Slope medium-visocisty oils. Many of these oils are depleted in their light-end hydrocarbons C7-C13. When a mixture of methane and natural gas liquid is injected, the ethane and components condense into the oil and decrease the viscosity of oil, making it easier for the water to displace the oil. From reservoir simulation, this process is estimated to enhance oil recovery compared to waterflood from 19 to 22% of the OOIP, which still leaves nearly 78% of the OOIP. Thus, further research should be directed at improving the recovery efficiency of these processes for viscous-oil reservoirs. Recovery efficiency depends on microscopic displacement efficiency and sweep efficiency. Microscopic displacement efficiency depends on pressure, (Dindoruk et al. 1992; Wang and Peck 2000) composition of the solvent and oil (Stalkup 1983; Zick 1986), and small-core-scale heterogeneity (Campbell and Orr 1985; Mohanty and Johnson 1993). Sweep efficiency of a miscible flood depends on mobility ratio (Habermann 1960; Mahaffey et al. 1966; Cinar et al. 2006), viscous-to-gravity ratio (Craig et al. 1957; Spivak 1974; Withjack and Akervoll 1988), transverse Peclet number (Pozzi and Blackwell 1963), well configuration, and reservoir heterogeneity, (Koval 1963; Fayers et al. 1992) in general. The effect of reservoir heterogeneity is difficult to study at the laboratory scale and is addressed mostly by simulation (Haajizadeh et al. 2000; Jackson et al. 1985). Most of the laboratory sweep-efficiency studies (Habermann 1960; Mahaffey et al. 1966; Jackson et al. 1985; Vives et al. 1999) have been conducted with first-contact fluids or immiscible fluids at ambient pressure/temperature and may not be able to respresent the displacement physics of multicontact fluids at reservoir conditions. In fact, four methods are proposed for sweep improvement in gasflooding: WAG (Lin and Poole 1991), foams (Shan and Rossen 2002), direct thickeners (Xu et al. 2003), and dynamic-profile control in wells (McGuire et al. 1998). To evaluate any sweep-improvement methods, one needs controlled field testing. Field tests generally are expensive and not very controlled; two different tests cannot be performed starting with identical initial states, and, thus, results are often inconclusive. Field-scale modeling of compositionally complex processes can be unreliable because of inadequate representation of heterogeneity and process complexity in existing numerical simulators. There is a need to conduct laboratory sweep-efficiency studies with the MCM fluids at reservoir conditions to evaluate various sweep-improvement techniques. Reservoir-conditions laboratory tests can be used to calibrate numerical simulators and evaluate qualitative changes in sweep efficiency. We have built a high-pressure quarter-five-spot model where reservoir-conditions multicontact WAG floods can be conducted and evaluated (Dao et al. 2005). The goal of this paper is to evaluate various WAG strategies for a model oil/multicontact solvent in this high-pressure laboratory cell. In the next section, we outline our experimental techniques. The results are summarized in the following section.

scholarly journals Experimental Investigation on Factors Affecting Oil Recovery Efficiency during Solvent Flooding in Low Viscosity Oil Using Five-Spot Glass Micromodel

2014 ◽  
Vol 5 (1) ◽  
pp. 205-222
Author(s):  
Hamed Hematpur ◽  
Mohammad Parvaz Davani ◽  
Mohsen Safari
Keyword(s):  
Experimental Investigation ◽  
Oil Recovery ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Recovery Efficiency ◽  
Butyl Ether ◽  
Factors Affecting ◽  
Low Viscosity ◽  
Viscous Oil ◽  
Glass Micromodel

Lack of experimental study on the recovery of solvent flooding in low viscosity oil is obvious in previous works. This study concerns the experimental investigation on oil recovery efficiency during solvent/co-solvent flooding in low viscosity oil sample from an Iranian reservoir. Two micromodel patterns with triangular and hexagonal pore structures were designed and used in the experiments. A series of solvent flooding experiments were conducted on the two patterns that were initially saturated with crude oil sample. The oil recovery efficiency as a function injected pore volume was determined from analysis of continuously captured pictures. Condensate and n-hexane were employed as base solvents, and Methyl Ethyl Ketone (MEK) and Ethylene Glycol Mono Butyl Ether (EGMBE) used as co-solvents. The results revealed that not only does the solvent flooding increase the recovery in low viscosity oil but also this increase is evidently higher with respect to viscous oil. But, type of solvent or adding co-solvent to solvent does not noticeably increase the recovery of low viscosity oil. In addition, further experiments showed that presence of connate water or increasing injection rate reduces the recovery whereas increasing permeability improves the recovery. The results of this study are helpful to better understand the application of solvent flooding in low viscosity oil reservoirs.

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