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Huang, Hai (Xi'an Shiyou University, Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta) | Chen, Xin (University of Alberta) | Li, Huazhou (University of Alberta)
Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity. As such, spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing. The chemical agents added to the injected water can alter the interfacial properties, which could help further enhance the oil recovery by spontaneous imbibition. This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition. We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO 2), and a series of house-made deep eutectic solvents (DES3-7, 9, 11 and 14).
Smalley, P. C. (Imperial College London) | Muggeridge, A. H. (Imperial College London) | Dalland, M. (Norwegian Petroleum Directorate) | Helvig, O. S. (Norwegian Petroleum Directorate) | Høgnesen, E. J. (Norwegian Petroleum Directorate) | Hetland, M. (Norwegian Petroleum Directorate) | Østhus, A. (Norwegian Petroleum Directorate)
This paper presents an improved approach for rapid screening of candidate fields for EOR and estimation of the associated incremental oil recovery, and the results of applying it systematically to oil fields on the Norwegian Continental Shelf (NCS), an area that already has a high average recovery factor (47%). Identifying, piloting and implementing new improved recovery methods within a reasonable time is important if substantial remaining oil volumes on the NCS are not to be left behind. The approach uses up-to-date screening criteria, and has more sophisticated routines for calculating screening scores and incremental oil recovery compared to previous published methods. The EOR processes screened for are: hydrocarbon miscible and immiscible WAG, CO 2 miscible and immiscible WAG, alkaline, polymer, surfactant, surfactant/polymer, low salinity, low salinity/polymer, thermally activated polymers and conventional near well gel treatments. Overall screening scores are derived from sliding-scale scores for individual screening criteria, weighted for importance, and with the ability to define nonzero scores when noncritical criteria are outside their desired range, so avoiding the problem of processes being ruled out completely even though rock or fluid properties are only marginally outside the threshold of applicability.
Kaiser, Anton (Clariant Oil Services) | White, Alan (Clariant Oil Services) | Lukman, Andi (Clariant Oil Services) | I, Istiyarso (Clariant Oil Services) | Gernand, Martin (Clariant Oil Services) | ShamsiJazeyi, Hadi (Clariant Oil Services) | Wylde, Jonathan (Clariant Oil Services) | Alvarez, Lourdes (Clariant Oil Services)
The use of alkaline surfactant polymer flooding techniques is becoming more commonplace, particularly in projects where heavier and more viscous crude oil is produced. While the efficacy of increasing recovery factors cannot be disputed, often there is little consideration given to the implications of these EOR chemicals breaking through into producer wells and entering the produced water handling system. The impact caused by EOR chemical breakthrough can be varied, but most commonly the efficacy of oil/water separation is seriously affected. The contribution that EOR chemicals can have on reservoir souring is often underestimated, as is the effect they can have upon standard production chemicals such as scale and corrosion inhibitors.
With the depletion of light oil, heavy oil is becoming one of the most promising resources to meet future energy consumption. It is estimated that total resources of heavy oil are 3396 billion barrels worldwide. Water flooding can only achieve less than 20% of heavy oil recovery. Thermal recovery has been proven as a feasible method to recover heavy oil. But it is not suitable for thin layers and deep reservoirs due to excessive heat loss. Polymer flooding and CO2 flooding are potential EOR techniques for the heavy oil reservoirs not suitable for thermal recovery. However, polymer degradation and high costs seriously hinder its field applications. Carbon Dioxide immiscible flooding effectively recovers heavy oil thanks to several mechanisms, such as oil swelling, viscosity reduction and blow-down recovery. This paper discusses the developments in CO2 immiscible flooding at laboratory scale as well as field scale. Laboratory tests show that CO2 can significantly improve heavy oil recover by 30%. Several field cases in USA, Turkey and Trinidad are reviewed. Field experiences show that CO2 flooding is a successful EOR method for heavy oil fields. However, some issues are encountered in field applications, including early gas breakthrough, corrosion, CO2 availability and high costs.
Water alternating gas (WAG) injection has been a popular method for commercial gas injection projects worldwide. The injection of water and gas alternatively offers better mobility control of gas and hence, improves the volumetric sweep efficiency. Although the WAG process is conceptually sound, its field incremental recovery is disappointing as it rarely exceeds 5 to 10 % OOIP. Apart from operational problems, the WAG mechanism suffers from inherent challenges such as water blocking, gravity segregation, mobility control in high viscosity oil, decreased oil relative permeability, and decreased gas injectivity.
This paper addresses the aforementioned problems and proposes a new combination method, named as the chemically enhanced water alternating gas (CWAG), to improve the efficiency of WAG process. The unique feature of this new method is that it uses alkaline, surfactant, and polymer as a chemical slug which will be injected during WAG process to reduce the interfacial tension (IFT) and improve the mobility ratio. In a CWAG process, a chemical slug is chased by water, preceded by gas slug and followed by alternate CO2 and water slug or chemical slug injects after one cycle of gas and water slug. Essentially CWAG involves a combination of chemical flooding and immiscible carbon dioxide (CO2) injections. These mechanisms are IFT reduction, reducing water blocking effect, mobility control, oil viscosity reduction due to the CO2 dissolution and oil swelling.
CMG's STARS was used to study the performance of the new method using some of the data found in the literature. It is a chemical flood simulator that can simulate all aspects of chemical flooding, and it can also handle immiscible CO2 injection features by considering K-value partitioning. The sensitivity analysis shows that the new method gives a better recovery when compared to conventional WAG. This study shows the potential of CWAG to enhance oil recovery.
This screening study has been applied on a group of offshore carbonate oil reservoirs. The methodology is based on the EOR screening criteria set forth by Taber et. al.1,2 enriched with additional screening criteria. The EOR techniques screened included solvent flooding (miscible, immiscible hydrocarbon and CO2 Gas flooding), chemical flooding (Polymer flooding, and Surfactant and Polymer flooding), as well as Thermal flooding (Steam injection and In-situ combustion) techniques. The screening study investigated the challenging and the killing parameters of each technique if any, indicating the most applicable EOR technique.
By comparing the depth and API gravity data of the reservoirs under study to that of the worldwide producing EOR projects, it was possible to define at a glance which EOR methods have been already experienced for the same conditions of reservoir depth and API oil gravities. Furthermore, by considering the relatively high pressure and temperature of the heterogeneous carbonate reservoirs under study, with its low viscosity oil, and the associated high salinity formation water, several EOR methods can be discarded including: Steam Injection, In Situ Combustion, and Polymers.
Two methods were found to be most suitable for most of the reservoirs: Miscible Hydrocarbon and CO2 Gas injection. Minimum Miscibility Pressure (MMP) has been estimated using correlations. A miscible gas injection could be achieved in most of the reservoirs by adding 2 to 13% C3-C4 to processed gas. CO2 mimimum miscibility pressure, MMP, is expected to be about 1000 psi lower than most of the reservoir pressures, making CO2 miscible flooding to be easily achieved.
Surfactant Polymers flooding could reduce Remaining Oil Saturation in reservoirs with more than 50mD permeability. This technology is less mature, than other EOR technologies. It is yet too challenging due to the high salinity, high temperature and carbonate formation.
There are about thirty giant fields comprising half of the world's hydrocarbon resources, and most of them are categorised as mature with substantial remaining reserves. Effective recovery of the remaining hydrocarbon reserves is crucial to meet the ever increasing world energy demand. In addition to effective reservoir managenement and improved oil recovery techniques, many operators have started applying some EOR techniques to increase current oil production as well as increase oil recovery factors for meeting current and future energy demand. Since most EOR projects are capital intensive with high risk of undesirable consequences in case of failure, most EOR projects have to go through the following steps:
• EOR screening study,
• Dedicated laboratory and reservoir simulation studies,
• EOR piloting, conditional to favorable results could lead to
• Full field application.
Before launching the dedicated EOR laboratory and reservoir studies for a group of offshore carbonate oil reservoirs, a general study has been adopted to screen the available EOR techniques to identify the:
• Promising EOR techniques that can be further considered.
• Challenging factors for applying variable EOR techniques, Killing factors (physical reasons related to reservoir condition) for applying some EOR techniques which cause not to be further considered.
Karaoguz, Osman K. (Consultant) | Topguder, Nazan Necibe Senol (Turkish Petroleum Corp.) | Lane, Robert H. (The Petroleum Institute) | Kalfa, Ulker (Turkish Petroleum Corp.) | Celebioglu, Demet (Turkish Petroleum Corp.)
This paper covers the successful pilot field application of polymer gels for reservoir conformance improvement in the ongoing CO2 injection project at Bati Raman heavy-oil field in southeastern Turkey. Bati Raman is a naturally fractured carbonate reservoir in which the heterogeneities and the unfavorable mobility ratios between CO2 and the heavy oil cause inefficient sweep of the reservoir. These conditions prompted the pilot application of a conformance-improvement fracture-plugging (flowing) gel system in three wells in July 2002. Based on injection tests performed in the field, approximate treatment volumes were estimated to be on the order of 10,000 bbl for each well. Volumes actually pumped ranged from approximately 6,500 to 11,000 bbl. All three of the wells showed a gradual increase in injection pressure during treatment, indicating a decrease in injectivity index as treatment progressed. During one treatment, an offset producer experienced changes in fluid level consistent with rapid pressure transmission via the connecting fracture early in the treatment, with later loss of such communication. This behavior provides direct evidence of fracture plugging during treatment (Lane 2002).
A mechanistic semianalytical model based on previously published laboratory work (Lane and Seright 2000) obtained a good match with the field data. The rate/pressure data were fed into the model, and effective fracture widths were backcalculated. Comparisons of results with the Formation MicroImager (FMI) log findings are explained. Gel-monitor well responses were scaled based on field data using a Fetkovich type decline-curve analysis. These studies enabled the incorporation of the effect of reservoir heterogeneities on the gel propagation radius so that future gel-treatment design parameters could be optimized.
Pre and post-treatment CO2 injection pressures and the rates are as shown in Table 1. Sweep efficiency was increased as defined by produced oil/injected gas ratio. The 1-year average post-gel oil rate from 19 offset producers is 720 STB/D, as compared with a pre-gel oil rate of 645 STB/D. The rate of increase from the treatments is thus 75 B/D, or 12%, which indicates a payout time of 12 months. Keeping this enlightened approach and seizing on the key concepts, four more CO2 injector wells were treated in 2004 to follow up on the encouraging results.
Bati Raman field is the largest oil field in Turkey, having an estimated 1.85 billion bbl of heavy-oil reserves. It is located in southeast Turkey (Fig. 1) and contains low-pressure, low-gravity (10 to 13°API) oil at an average depth of 4,300 ft. Its reservoir rock, the Garzan formation, is heterogeneous, fractured, vugular limestone. Average matrix porosity is 18%, with mainly vugs and fissures, and secondary porosity is 1 to 2%. The typical matrix permeability by core analysis is 10 to 100 md; however, well tests show effective permeabilities in the range of 200 to 500 md, confirming the contribution of secondary porosity. The field was first placed on production in 1961 and had produced 1.5% of its reserves by 1986, when Turkish Petroleum Corp. (TPAO) began immiscible CO2 injection. Through 2003, 5% of the reserves had been produced, which is still an unexpectedly low value. Production rate has declined drastically since 2000. TPAO is seeking the most applicable methods to impede or reverse the decline. Polymer gel treatments were an obvious enhanced-oil-recovery (EOR) method to increase CO2 sweep efficiency.