Enhanced Oil Recovery by CO2 Injection in Fractured Reservoirs. Emphasis on Wettability and Water Saturation
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The work presented in this Thesis is part of ongoing research on Enhanced Oil Recovery (EOR) in fractured reservoirs within the reservoir physics research group at the Department of Physics and Technology, University of Bergen. This research group has previously identified chemical EOR to alter wettability, miscible gas injection and mobility control by foam and polymers to be the most promising methods for applications on the Norwegian Continental Shelf. In this Thesis a series of laboratory scale injection tests have thus been performed to mimic oil recovery in fractured carbonate reservoirs to understand fluid flow dynamics when applying the above mentioned EOR techniques. The objective is to improve the understanding of the governing displacement processes in order to contribute to increased oil recovery. Wettability controls the fluid distribution on pore scale level in porous rock material and is emphasized throughout this Thesis. The first objective of the experimental work was to establish stable wetting preferences uniformly distributed in core samples cut from strongly water-wet outcrop rock material. In a reservoir a wettability change towards less water-wet preference occurs over geologic time when hydrocarbon components adsorb on the rock surface. A dynamic aging technique, designed to establishing uniform wetting preferences by continuously flowing crude oil through core samples, was used to establish wetting states being typical for partly waterflooded areas in North Sea chalk fields. Paper 1 reports the results from systematic investigation of wetting stability in aged Rørdal chalk, an analogue to the Ekofisk field. The effect of initial water saturation and aging time was studied and a systematic decrease in endpoint water saturation for spontaneous imbibition was observed with i) a decreasing water saturation during aging and ii) increasing aging time. Repeated cycles of spontaneous imbibition tests, forced waterfloods and drainage were performed in the same core sample to measure the stability of the Amott-Harvey water index, Iw. Typical reservoir conditions for a large transition zone, residual oil zones or partly waterflooded areas were also investigated by varying the initial water saturation before the spontaneous imbibition test. The established Iw (ranging from 0.39 to 0.80), was stable during several flooding cycles. The aging technique presented in Paper 1 established a range of stable wetting states on the water-wet side in outcrop analogues of North Sea chalk. Weakly water-wet samples have less potential for spontaneous imbibition of water. EOR can therefore be achieved by adding chemicals to the injection brine through wettability enhancement: if the matrix becomes more water-wet more water will spontaneously imbibe and more oil will be produced. Previous laboratory studies have shown that injection strategies using seawater as the injection fluid can benefit from potential determining ions. Experiments by sulfate enriched waterfloods with mineral oil as oil phase demonstrated increased oil recovery up to 35 % in Stevns chalk, while no EOR- effect was observed in Rørdal chalk. Paper 2 presents the wettability altering effects during sulfate enriched waterfloods in aged Rørdal and Stevns chalk core samples saturated with crude oil. The average additional recovery with the presence of sulfate was found to be 43 %OOIP for Stevns chalk and 12 %OOIP for Rørdal chalk. These experiments showed that sulfate increased the potential for spontaneous imbibition during waterfloods and that the effect varied with the oil composition, the chalk mineralogy, reservoir temperature and with solvent properties. Several of the North Sea oil fields have been waterflooded for decades and in general this has been a great success. However, there is still a great potential for enhanced oil recovery which call for a new generation of EOR techniques. Miscible CO2 injection for enhanced oil recovery (CO2-EOR) in mature oil fields has the potential to safely store CO2 and reduce atmospheric emissions, while at the same time significantly enhance oil production to meet the increasing energy demand. The main part of the work, presented in Paper 3-6, reports on CO2-EOR injection tests in fractured core samples at varying experimental conditions using different injection strategies. Experimental results obtained in this Thesis exhibited in general that CO2-EOR in fractured systems was characterized by: 1) a rapid breakthrough of CO2 where most of the oil was produced after CO2-breakthrough, 2) a low oil production rate from the onset of CO2 injection, 3) a long tail production and 4) no apparent differential pressure across the core length, which indicated diffusion dominated recovery process. Secondary CO2 injections, with no preceding waterflood, was generally very efficient in terms of oil recovery, up to 96 %OOIP was observed recovered. Reduced oil recovery efficiency was observed when CO2-onset started at higher initial water saturation and after waterfloods i.e. as a tertiary recovery method, likely due to water shielding. Higher initial water saturation may reduce or prevent contact and mixing between the injected gas and matrix oil. In moderately water-wet systems the water shielding effect was less prominent. The effect of wettability in CO2-EOR recovery strategies is discussed in Paper 3 and Paper 6. Paper 3 presents results from injection tests in core samples saturated with a pure mineral oil (n-Decane) and crude oil (hydrocarbon composition: 97 % C7+, 28 % C30+). Oil recovery was lower and slower in fractured core samples saturated with crude oil compared to a pure mineral oil (n- Decane), likely due to the development of multi-contact miscibility and a less favorable mobility ratio. The influence of fracture permeability and matrix size (diffusion length) in cylindrical core plugs and larger rectangular blocks are investigated in Paper 4. An increasing diffusion length i.e. the distance from the CO2- filled fracture to the end of porous system resulted in decreased oil recovery efficiency. By reducing the fracture permeability the oil recovery efficiency was improved. Viscous fingering, gravity override and flow in high permeability fractures or thief zones will reduce the volumetric sweep and lead to early gas breakthrough in the producer and a low oil recovery rate per unit of injected CO2. CO2 is typically in its liquid or supercritical state at reservoir conditions with a liquid-like density and gas- like viscosity. Apparent viscosity will be reduced in CO2-foam, therefore generation of foam will give CO2 a more favorable mobility ratio relative to oil and water, divert flow to increase sweep and add a viscous component to the oil displacement process. Paper 5 presents a sequential CO2 injection strategy: when pure CO2 injection efficiency decreases, co-injection of CO2 and surfactant starts. The strategy of switching to foam during pure CO2 injection accelerated the oil production and increased the end point oil recovery and was observed to most effective in heterogeneous rock material. Paper 6 presents a conceptual numerical model where foam is simulated by reducing the fracture conductivity. A history match with experimental data obtained during secondary CO2 and CO2-foam injections tests in oil and brine saturated cylindrical core plugs was used to validate the model. Foam significantly increased the experimentally measured oil recovery rate compared to pure CO2 injection by adding a viscous component to the oil recovery process. The increased pressure gradients measured experimentally was a result of the decreased CO2 mobility by increasing the apparent CO2 viscosity with foam. The CO2-foam injection tests all showed an accelerated oil recovery rate compared to pure CO2 injections, with increased differential pressure across the core due to flow diversion. The numerical model showed a decreasing contribution from diffusion on oil recovery as the matrix size/diffusion length increased. The main conclusions in this Thesis are: A dynamic aging technique using crude oil established a range of uniform, stable wetting preferences in originally strongly water-wet outcrop chalk samples. Experimental studies showed that sulfate enriched waterfloods may be an attractive EOR-method to improve the water-wetting state of the rock surface. Laboratory evaluations of miscible CO2 injections for EOR in fractured systems demonstrated a very efficient displacement process in terms of final oil recovery, up to 96 %OOIP was recovered. Increased water saturation decreased oil recovery efficiency during CO2 injections, particularly after efficient preceding waterfloods in strongly water-wet fractured systems. Foam as EOR-mobility control in fractured systems improved conformance control and reduced CO2 channeling in high permeable fractures.
Has partsPaper I: Steinsbø, M., Graue, A., Fernø, M.A., 2014. A systematic investigation of wetting stability in aged chalk. SCA 2014-37. International Symposium of the Society of Core Analysts, Avignon, France. This article is not available in BORA.
Paper II: Steinsbø, M., Graue, A., Fernø, M.A., 2015. EOR by sulfate enriched waterfloods in aged outcrop chalk samples. In preparation for being submitted to Journal of Petroleum Science and Engineering. Manuscript. This article is not available in BORA.
Paper III: Steinsbø, M., Brattekås, B., Ersland, G., Fernø, M.A., Graue. A., 2014. Supercritical CO2 injection for enhanced oil recovery in fractured chalk. SCA2014-092. International Symposium of the Society of Core Analysts, Avignon, France. This article is not available in BORA.
Paper IV: Steinsbø, M., Brattekås, B., Ersland, G., Bø, K., Oppdal, I., Tunli, R., Graue, A., Fernø, M.A., 2015. Foam as Mobility Control for Integrated CO2-EOR in Fractured Carbonates. IOR 2015 – 18th European Symposium on Improved Oil Recovery, Dresden, Germany. This article is not available in BORA. The published version is available at: 10.3997/2214-4609.201412125
Paper V: Fernø, M.A., Steinsbø, M., Eide, Ø., Ahmed, A., Ahmed, K., Graue, A., 2015. Parametric study of oil recovery during CO2 injections in fractured chalk: Influence of fracture permeability, diffusion length and water saturation. Journal of Natural Gas Science & Engineering. This article is not available in BORA. The published version is available at: 10.1016/j.jngse.2015.09.052
Paper VI: Fernø, M.A., Eide, Ø., Steinsbø, M., Langlo, S.A.W., Christophersen, A., Skibenes, A., Ydstebø, T., Graue, A., 2015. Mobility control during CO2 EOR in fractured carbonates using foam: Laboratory evaluation and numerical simulations. Journal of petroleum Science and engineering, 135, 442–451. This article is not available in BORA. The published version is available at: 10.1016/j.petrol.2015.10.005