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Abstract Based on the non-Darcy flow characteristics of surfactant flooding, considering the changes of threshold pressure and influence of surfactant on convection, diffusion, adsorption and retention, a surfactant flooding mathematical model of three-dimensional, two-phase, three-component was established. A new method for the treatement of relative permeability curve and theoretical calculation equation for adsorption quantity of surfactant were derived, which enhances the matching degree between mathematical model and field practice. The method of implicit pressure, explicit saturation, and implicit concentration was used to solve equations and a simulator was developed. This simulator was used to perform the numerical simulation study for the pilot test of surfactant flooding in Chao 522 Block of Daqing oilfield, the optimal injection scheme was selected. After the optimized plan was carried out in oilfield, the desirable effects, like pressure-reducing, injection rate increase, and oil recovery increase, were achieved. The average oil increase for single well reaches 30%, the ratio of cost to revenue is above 1:3, so the very good development effect and economic effect were obtained. Introduction The indoor experiments show that the surfactant flooding can lower the threshold pressure and increase the oil recovery efficiency of low permeability oilfield(Liu et al. 1987). Several pilot tests of surfactant flooding were carried out in Daqing's low permeability oilfields, such as Yushulin oilfield and Chaoyanggou oilfield, the objectives of pilot tests are to reduce the injection pressure, to increase the injection rate and to enhance the oil recovery. The experimental screening of surfactant was finished, but the theoretical study on surfactant flooding in low permeability oilfield is few, and the reservoir simulation software that include the threshold pressure is not reported(Sun et al., 1996). Because the cost of surfactant is comparatively high, the amount of surfactant used should be first determined for the field application to obtain the maximum economic benefit, so it is very important to conduct reservoir numerical simulation study. On the basis of compositional model, a mathematical model of surfactant flooding was established, in which the changes of threshold pressure and relative permeability which are caused by surfactant flooding, and influence of adsorption and retention of surfactant in the reservoir are included in the model. This model was used to optimize the injection plan for pilot test of surfactant flooding in Chaoyanggou oilfield of Daqing, in order to provide a theoretical basis of decision for the development of oilfield. Experiment of Surfactant Flooding on Low Permeability Cores Experimental Results In order to study the non-Darcy flow characteristics of surfactant flooding in low permeability reservoir, the surfactant flooding experiment on reservoir cores was conducted. The displacing liquid is solution of nonionic alkanol acid amide surfactant and auxiliary agent, which can reduce the interfacial tension between crude oil and water of Chaoyanggou oilfield to reach ultra low interfacial tension(IFT). The experimental results are shown in Table 1. As we can see from Table 1, after injecting the displacing liquid of surfactant, the pressure of succeeding waterflood reduced by 40% compared with value of pre-injection of surfactant solution, so the displacing pressure was significantly reduced, compared with waterflood, the recovery efficiency is enhanced by 5%. In order to further determine the effect of surfactant concentration on the threshold pressure gradient, the relationship between surfactant concentration, water saturation and threshold pressure gradient were measured(Fig. 1). As is shown in Fig. 1, with the increase of surfactant concentration and water saturation, the threshold pressure gradient reduces gradually, but the decrease extent becomes smaller.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The giant Gullfaks Main Field comprises Statfjord, Cook and Brent Formations of Early to Middle Jurassic. The reservoir is complex due to large number of faults and extreme permeability contrast ranging from several Darcies in the Tarbert to milli-Darcy in the Cook. The highly productive sands are poorly consolidated causing sand production problem. Reservoir fluid in some of the areas contains high H2S. Uncertainties associated with structures, degree of communication, extreme contrast in reservoir properties and effective control of sand and H2S pose a great challenge for reservoir management. Despite the challenges, the recovery factor on Gullfaks Main Field is high. A total of 335 Sm3 of oil has so far been produced, which amounts to an overall recovery factor of 56% (60% in the Brent Formation). This high recovery factor is attributed to effective reservoir management. The management strategy involves conservation of reservoir energy, implementation of simple and advanced strategies, systematic and sustained collection of data, and continuous application of improved recovery technologies. Conservation of energy is achieved through water and gas injection. Simple and advanced strategies include selective perforation of wells, sand control, zone isolation, multi-target wells, controlled drainage through DIACS technology, through-tubing drilling, etc. Data collection involves 3D and 4D seismic, core and well log, RFT/MDT pressure, PLT, RST saturation, well completion, production and injection, etc. Improved recovery techniques, studied and some of them implemented, consist of infill-drilling, water and WAG injections, polymer assisted surfactant flooding, microbial injection, CO2 injection, etc. The current IOR initiatives are meant to extend the production life of the field to 2030 and thus meet the ambition of recovering 400 MSm3 of oil. This paper summarizes the reservoir management challenges, techniques and technologies applied to evaluate and monitor the reservoir performance, and the strategies to enhance oil production. Introduction The Gullfaks field is currently owned 70% by StatoilHydro and 30% by Petoro. StatoilHydro is the operator. The field is located mostly in block 34/10 in the Norwegian sector of the North Sea (Fig. 1). The Gullfaks area with field, discoveries and prospects are shown in Fig. 2. The area includes nine production licenses. The red dotted line divides the area into two: Gullfaks main and Gullfaks satellites. Gullfaks satellites consist of Gullfaks Sør, Rimfaks, Gullveig, Skinfaks and Gulltopp. Gullfaks main represents the main reservoir containing 78% of the total in-place oil volumes and 88% of the recoverable reserves. This paper solely deals with reservoir management of the main field and hence no more discussion will be made on the satellites. Hereafter, if not stated otherwise, the main field will be referred to as the Gullfaks field. Block 34/10 was awarded to Statoil, Norsk Hydro and Saga Petroleum in June 1978. The Gullfaks field was discovered in the same year by the first exploration well 34/10–1, which encountered a 160m oil column in the Brent Group and penetrated water-bearing Cook and Statfjord formations. Exploration wells 34/10–3 to 6 appraised the western part of the field and established the oil-water-contact (OWC) in the Brent Group. A deeper hydrocarbon system in the Cook formation was discovered by 34/10–7, whereas well 34/10–11 in the north-eastern part of the block showed a deeper OWC and a new oil-bearing system in the Statfjord formation. The appraisal phase of the main field ended in 1983, while the appraisal of the satellites continued up to 2002. More than 20 exploration and appraisal wells were drilled to assess the full potential of the field. Based on structural understanding from seismic and well data, a 2-phase development plan was proposed 1. Following the commerciality report in late 1980, the authorities approved a field development plan (Phase-I) in October 1981 allowing the production of Brent Group reserves in the western part of the field from two concrete gravity base platforms. The field was set on production in December 1986 from five pre-drilled subsea wells connected to Gullfaks A-platform (GFA). Gullfaks B platform (GFB) was commissioned in February 1988. The authorities approved the development of the eastern part (Phase-II) in 1985 from a third concrete gravity base platform. Gullfaks C platform (GFC) was put on production in January 1990.
- Geology > Mineral (0.93)
- Geology > Geological Subdiscipline > Stratigraphy (0.93)
- Geology > Structural Geology > Fault (0.68)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.89)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.46)
- Europe > Norway > North Sea > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > NOAKA Project > Krafla North Prospect > Etive Formation (0.99)
- (34 more...)
Abstract Despite the numerous experimental studies, there is a lack of fundamental understanding about how the local and global heterogeneity control the efficiency of polymer flooding. In this work a series of water and polymer injection processes are performed on five-spot glass micromodels which are initially saturated with the crude oil at varying conditions of flow rate, water salinity, polymer type and concentration. Three different pore structures in combine with different layer orientations are considered for designing of five different micromodel patterns. It has been observed that the oil recovery of water flooding is increasing with the salinity concentration, for the ranges studied here. While, it shows there is an optimum value of concentration in which maximize the oil recovery in polymer flooding. The results confirmed that the highest oil recovery is obtained when the layers are perpendicular to the mean flow direction for both water and polymer flooding. Also, the oil recovery in polymer flooding increases with the increase of layer inclination angle, however it does not increase for waterflooding. In addition, the oil recovery is strongly affected by the local heterogeneity which is near injection zone. This study demonstrates the applicability of micromodel for studying of enhanced oil recovery techniques in locally and globally heterogeneous five-spot models. Introduction Water flooding is being widely used in the petroleum industry and has been considered as a simple inexpensive secondary recovery method. Craig (1980) summarized the reasons of waterflooding popularity among other fluid injection methods asavailability of water, easy way of water injection, ability of water to spread through pay zone, and water efficiency to displace oil through pay zone. On the other hand, one of the most popular drawbacks of waterflooding was recognized to be its poor sweep efficiency. Polymer flooding can yield significant increases in percentage recovery accompanied with a complex mechanism. However, analyzing the performance of a polymer flooding in a field project requires a vast knowledge not only of the polymer solution's rheological behavior, but also of the local and global heterogeneities which affect areal sweep efficiency of the process. Adding suitable polymer solution to the injected water would result in reduction of water mobility, and so the oil recovery will increase. According to Needham (1987), polymer solutions may lead to an increase in oil recovery over that from conventional waterflooding by three potential ways:through the effects of polymers on fractional flow, by decreasing the water/oil mobility ratio, and by diverting the injected water from zones that have been swept. The above three effects can make the polymer flooding process more efficient. Sweep efficiency is defined as the ratio of volumes of oil contacted by displacing agent to volume of oil originally in place, and is negatively affected by many factors such as the unfavorable mobility ratio (greater than one), complicated pore structure and characteristics of oil-wet on the rock surfaces (which impede oil transport by capillary force), and the reservoir rock heterogeneity (Craig 1980; Han et al. 1999; Lake 1989). However, nearly all oil reservoirs are heterogeneous because of the wide variations in porosity, permeability, depositional environments, and existence of naturally fractured systems. According to van Poollen (1980) in terms of enhanced oil recovery, the divergence of reservoir permeability is a significant factor. The permeability variation can have a profound effect on the flow of fluids in a reservoir and thereby influence oil recovery.
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.74)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)