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The mechanisms of Microbial Enhanced Oil Recovery (MEOR) are generally thought to be through oil biodegradation, production of biosurfactants, biogases, low molecular acids and biopolymers by microbes. The first four processes contribute to Interfacial Tension (IFT) reduction while the final one to plugging high permeability zones. Microbes can produce diverse metabolites thereby modifying the oil-water IFT in an oil reservoir. This study attempts to investigate the effect of microbial metabolites on the oil viscosity and IFT under reservoir P/T conditions.
A reservoir fluid with 20% crude oil and 80% formation water was treated with indigenous microbes for 21 days under anaerobic condition using molasses (5%) as nutrients. The microbially treated and the un-treated oils were analysed geochemically by using Gas Chromatography-Mass Spectrometer (GC-MS). The oil density, viscosity and the oil-water IFT of both the un-treated and bio-treated oils were measured under reservoir P/T conditions.
The analytical results indicated that there were no significant difference in chemical compositions and densities among different oil samples, suggesting little or none microbial biodegradation present. The effect of biogases and low molecular acids was excluded because of the measurement methodology used.
In contrast to the un-treated oil, the IFT of the bio-treated crude oil was found to be reduced from the un-treated 7.2 to 3.7×10-3 mN/m, a 48% reduction. The oil viscosity of the bio-treated crude oil was decreased by 50%. The viscosity and IFT reduction might be primarily due to the microbial metabolites (biosurfactants) produced, which may play a key role in altering the oil-water interface. Macro-micro emulsification was also observed at the oil-water interface. It is concluded that microbial metabolites could potentially reduce the oil viscosity (via emulsification) and improve the crude oil-water IFT under reservoir P/T conditions.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 2-4 July 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior. Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.
Screening for Enhanced Oil Recovery (EOR) processes is a critical step in evaluating future development strategies for depleted reservoirs under primary and secondary recovery. However, selecting the optimum EOR process for a given reservoir is challenging because it requires evaluating and comparing performance for various EOR processes, which is complex and time consuming.
This paper presents a new EOR screening model that can predict the performance of various gas- and water-based EOR processes based on simple reservoir properties. The model estimates the oil recovery from miscible and immiscible gas/solvent injection (CO2, N2, and hydrocarbons), low salinity water flood, polymer, surfactant-polymer, alkaline-polymer and alkaline-surfactant-polymer floods. The screening model is based on a set of correlations that were developed using the response surface methodology, which correlates the oil recovery at dimensionless times to the important reservoir and fluid properties and EOR process variables identified for each process. The results of the model have been validated against a number of field test and numerical simulation results.
The screening model provides the capability to screen a large set of reservoirs for a wide spectrum of EOR processes, to identify the good EOR targets and the optimum EOR process for the target reservoirs. In addition, this model easily performs sensitivity analysis without the need for numerical simulations, allowing teams to account for uncertainty in reservoir properties and optimization of flood design. Finally, the methodology can be applied for developing screening models for other oil recovery mechanisms such as thermal (steam injection, SAGD), microbial EOR and other methods.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Weidong (Research Institute of Petroleum Exploration and Development, CNPC) | Cheng, Lijing (Oil Production Engineering Research Institute of Dagang Oilfield) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration and Development, CNPC)
Surfactant-Polymer (SP) flooding has attracted lots of attention among chemical combination flooding researchers in recent years. Pilot tests of SP flooding in China were introduced and key factors influencing the performance of pilot tests were analyzed in this paper. Main technological problems occurred in pilot tests were indicated. Suggestions concerning technology improvement and development were given.
About ten SP flooding pilot tests were carried out in China since 2003. These target reservoirs were characterized with high permeability and low permeability sandstone, conglomerate, and high temperature and high salinity ones respectively. At present, the performance of SP flooding pilot tests in Gudong Block 6 and Gudong Block 7 of Shengli oilfield have shown good enhanced oil recovery (EOR) effect. It confirmed SP flooding could improve both of oil displacing efficiency and sweep efficiency and EOR ability for SP flooding is better than that of polymer flooding. EOR effect of SP flooding can be reflected from the following two aspects. Firstly, with SP slug injecting, the pressure of injection well increased and fluid entry profile was adjusted. The performance of profile control was favorable. Secondly, ultralow interfacial tension could be achieved and residual oil was displaced significantly. SP flooding showed stronger ability in decreasing water cut and increasing oil production than polymer flooding. The production history data showed that main factors influencing EOR were the corresponding relationship between injection wells and production wells, the chemical formula properties and the injection amount of SP system. The favorable oil production was obtained when the corresponding relationship between injection wells and production wells was good. The quality stability of SP formula could influence the flooding EOR performance greatly. Small injection slug size of chemical system would lead low EOR level.
The key technologies which should be improved and optimized for SP flooding are displacing agent quality, formula system stability, slug design, well pattern and so on.
Du, Yong (China University of Petroleum (East China)) | Wang, Yang (China University of Petroleum (East China)) | Jiang, Ping (China University of Petroleum (East China)) | Ge, JiJiang (China University of Petroleum (East China)) | Zhang, GuiCai (China University of Petroleum (East China))
In China, cyclic steam stimulation is the most widely applicable method for the development of common and ultra-heavy oil, and about 80% of thermal production is by CSS. Henan oilfield is one of the main producing areas of heavy oil in China and oil viscosity mainly ranges from 10000 to 30000mPa.s, belonging to ultra-heavy oil. After 6~8 cycles' huff and puff, the heating radius reaches to its economic limit and both oil and water recovery is low due to the unfavorable reservoir pressure. Though nitrogen can enhanced common heavy oil recovery after CSS, there are few reports about nitrogen assisted CSS for ultra-heavy oil. For these problems, this paper studies the feasibility and mechanism of nitrogen assisted CSS via laboratory experiments and simulation. Simulation results showed that it was feasible to inject nitrogen before CSS. Though nitrogen has little effect on the reduction of oil viscosity, the main mechanism of enhanced oil recovery was its good ability of heat insulation effect, so the heat loss of injected steam could be reduced and the heating radius was increased. Besides, compressibility coefficient of nitrogen was very large, so it could supply energy during exploitation process and avoid the rapid reservoir pressure drop. Pilot tests were conducted to several wells in Jinglou ultra-heavy oil reservoirs in Henan oilfield. Most wells achieved good effect. With the ratio of nitrogen to steam (volume ratio at standard conditions) increasing, the oil recovery got better. When the ratio was larger than 30, it had no better effect on enhanced oil recovery. These results are of significance for the development of ultra-heavy oil reservoirs.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration & Development, CNPC) | Weng, Rui (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration & Development, CNPC) | Luo, Yousong (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration & Development, CNPC)
For mature oil fields, foam flooding is an attractive chemical EOR technique and many pilot tests have been carried out in China. The performance of foam flooding pilot tests and its affect factors on oil recovery was discussed in this paper. The development trend and key technologies of foam flooding technique are pointed out.
Eighteen foam flooding pilot tests have been carried out in China from 1994 to 2010. Good performance have achieved in sixteen pilot tests. Through effects analysis of the pilot tests, three main aspects are concluded for affecting the performance of foam flooding tests. First, the characteristics of target reservoirs influence effects of foam flooding tests. The performance of foam flooding in higher oil viscous reservoirs is better than that in light oil reservoirs. The reservoir temperature and formation water salinity also influences the effects of foam flooding. Secondly, the chemical formula of foam solution and the size of slug influence the performance of foam flooding. The stability of foam formula influences the effects of foam flooding greatly. With the same amount of surfactant solution, the effect of high concentration small-sized slug is better than that in low concentration large-sized slug. Last, the injection method and gas liquid ratio can directly influence the foam performance in the reservoir, gas and liquid mixing injecting model is better than surfactant solution-alternation-gas (SAG) injection, and reasonable gas liquid ratio is important for guarantee good effects of foam flood.
At present, the trend of foam flooding in China is from nitrogen foam flooding and natural gas foam flooding to air foam flooding. The key technologies of foam flooding are the development of high stable foam formula with oil tolerance, salt and temperature resistance, good injection method and reasonable injection parameter etc.
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.
Foaming of nitrogen stabilized by C14-16 alpha olefin sulfonate in natural sandstone porous media, previously subject to water flooding, was studied experimentally. Foam was generated in-situ by co-injecting gas and surfactant solution at fixed foam quality. Effect of surfactant concentration on the foam strength and foam propagation was examined. X-ray CT scans were obtained to visualize the foam displacement process and to determine fluid saturations at different times. The experiments revealed that stable foam could be obtained in the presence of water-flood residual oil. CT scan images, fluid saturation profiles and mobility reduction factors demonstrated that foam exhibited a good mobility control in the presence of water-flood residual oil. This was further confirmed by a delay in the gas breakthrough. The experiments also proved that immiscible foam displaced additional oil from water-flooded sandstone cores, supporting the idea that foam is potentially an effective EOR method. Foam flooding provided an incremental oil recovery ranging from 13±0.5% of the oil initially in place for 0.1 wt% foam to 29±2% for 1.0 wt% foam. Incremental oil due to foam flow was obtained first by a formation of an oil bank and then by a long tail production due to transport of dispersed oil within the flowing foam. The oil bank size increased with surfactant concentration, but the dispersed oil regime was less sensitive to the surfactant concentration.
Buijse, Marten Adriaan (Shell Exploration & Production) | Tandon, Kunj (Shell Technology Centre Bangalore) | Jain, Shekhar (Shell Technology Centre Bangalore) | Jain, Amit (Shell Technology Centre Bangalore) | Handgraaf, Jan-Willem (Culgi B.V.) | Fraaije, Johannes G. E. M. (Leiden University)
Surfactant formulations are extensively being developed in the oil industry for Enhanced Oil Recovery (EOR) applications. Surfactants suitable for EOR will form an oil-brine microemulsion (µE) with ultra-low interfacial tension (IFT), necessary for
high recovery factors. Experimental screening of surfactants, to identify suitable formulations for reservoir conditions, is a laborious and time consuming process. In this paper we demonstrate an alternative, and novel, molecular modeling approach which is suitable for predicting µE properties and calculating optimum conditions. The molecular modeling simulations are based on the recently developed Method of Moments (MoM). The µE physics underlying the MoM is briefly reviewed in this
In the MoM the bending properties of the interfacial surfactant film are calculated as moments of the lateral stress profile. At optimum salinity the zeroth and first moments of the lateral stress profile are zero and the IFT will reach a minimum. In addition to optimum salinity, the bending rigidity (stiffness) of the surfactant film is another interesting microstructure property. The bending rigidity determines the oil/brine domain size, solubilization and magnitude of the IFT. The bending rigidity is accessible in the MoM via the saddle-splay modulus ks, which is calculated as the second moment of the lateral stress profile. It is shown in the paper how the shape of the lateral stress profile depends on molecular properties of the surfactant and on salinity.
MoM simulations were carried out using the coarse-grained Dissipative Particle Dynamics (DPD) method. This computational approach is highly scalable, while preserving the structural information of chemical components in the system. This makes the method useful while screening the wide design space of possible surfactant-oil-brine combinations. We will discuss the predictive technique and some validation examples of predicting optimum salinity for oil-brine micro-emulsions. We will then demonstrate the effect of surfactant structural parameters like chain length, cosolvent etc. on the optimum salinity of the microemulsions.
In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.
A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.
Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.
The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.