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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 Chemical injection in enhanced oil recovery (EOR) projects is a complex process because it involves multiple chemicals with complex fluids. Costs for even a small-scale pilot test could be up in the millions of US dollars (USD) and large-scale fieldwide expansion would be in the 100s of millions USD for onshore projects. Costs for offshore projects would increase by multiple folds compared to onshore projects with comparable sizes. This paper discusses (1) conventional designs for small-or large-scale injection facilities, (2) recent improvements in conventional designs, and (3) new concepts in chemical injection facility designs that can improve the quality, lower the cost, and reduce the lead time in the implementation of chemical EOR (CEOR) projects. Introduction Major CEOR processes can be classified into two categories: polymer applications and surfactant processes. Polymer applications include polymer flooding (PF), and polymer gels for profile modification and water shut-off.
- North America > United States (1.00)
- Asia > China (0.69)
- Asia > Malaysia > Kuala Lumpur > Kuala Lumpur (0.24)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (4 more...)
Abstract 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 10m (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 10m (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.
- North America > Canada > Alberta > Etzikom Field > 1117695 Etz 11-13-6-8 Well (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract CO2 is injected into mature reservoirs for both sequestration and EOR. The effect of CO2 flooding on asphaltene stability has been extensively addressed in literature. In contrast, asphaltene / water interaction has not received much attention in literature. The objective of the paper is to address the asphaltenic oil recovery by water alternating CO2 injection (WACO2) and asphaltene/ions interaction. Different water compositions, such as synthetic seawater (SSW) and low salinity water (LSW), Na2SO4, MgCl2 ions, and ion free water (DW), are used. SO4 and Mg ions were selected based on previous work on their interaction with chalk minerals and modifying the surfaces to more water wet. CO2 is injected in miscible mode within the WACO2 recovery process. For simplicity outcrop cores and model oil were used. Model oil consists of n-C10, 0.35wt% asphaltene (extracted from a Middle East crude oil) and natural surfactant (stearic acid, SA). The effects of water injection rates were also investigatd to address the oil recovery efficiency in the cores and assess the water/oil/rock interaction as a function of injection rates. Imbibition process with various water compositions was tested for cores unflooded and flooded with CO2. This is to address the effect of CO2 on the fluids interaction. It was shown that higher oil recovery was obtained when Mg solution was used as imbibing fluid after CO2 flooding compared to SO4 solution. The opposite was observed without the CO2 flooding where higher recovery was obtained when Na2SO4 solution was used as an imbibing solution compared to that with MgCl2 as imbibing fluid.
- Geology > Mineral > Sulfate (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
Abstract The natural pressure in hydrocarbon reservoirs is only sufficient in producing small amount of hydrocarbon at the end of the depletion stage. Therefore, in order to enhance or increase the hydrocarbon recovery, water or other fluids are injected into the formation to extract the hydrocarbon from the pore space. This common practice is known as Improved or Enhanced Oil Recovery (IOR or EOR). Foam is purposely used in some of the EOR displacement processes in order to control the mobility ratio, hence improving the volumetric sweep efficiency. The efficiency of a foam displacement process in EOR depends largely on the stability of the foam films. In laboratory, foam stability is usually measured through physical observation of the foam bubble in a glass tube. Unfortunately, this direct observation is not possible in the reservoir. Therefore, indirect measurement such as the measurement of electrokinetic signal would be a better alternative. This study aims to determine the correlation between the foam stability and the associated streaming potential signals which resulted from the flowing fluid in foam assisted water alternate gas (FAWAG) process. The experimental work will be conducted at the Reservoir and Drilling Engineering Laboratories at the Faculty of Petroleum and Renewable Energy Engineering (FPREE), UTM. The investigation includes sample preparation, sample analysis, displacing fluid formation, rheological properties test and electrokinetic signal measurement by using NI Data Acquisition System (NIDAS). It is expected that the burst of the foam bubble will change the pattern of the electrokinetic signals. The research findings could lead to a new approach in monitoring a FAWAG process. Application in the real field could benefit the oil and gas industry in term of making the EOR process more efficient and more economic.
- Europe (1.00)
- Asia (1.00)
- North America > United States > Texas (0.47)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (11 more...)
Effect of Continuous, Trapped, and Flowing Gas on Performance of Alkaline Surfactant Polymer ASP Flooding
Farajzadeh, R.. (1 Shell Global Solutions International, Rijswijk, The Netherlands) | Ameri, A.. (2 Delft University of Technology, The Netherlands) | Faber, M. J. (1 Shell Global Solutions International, Rijswijk, The Netherlands) | Van Batenburg, D. W. (1 Shell Global Solutions International, Rijswijk, The Netherlands) | Boersma, D. M. (1 Shell Global Solutions International, Rijswijk, The Netherlands) | Bruining, J.. (2 Delft University of Technology, The Netherlands)
Abstract Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock. In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, re-injection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created. To the best of our knowledge, there are no data in the literature concerning the influence of in-situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (non-dissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, either flowing or trapped. We found that the ultimate residual oil saturation in most experiments is similar to the case without gas. When free gas is present in the porous medium, the oil-bank production occurs earlier, because a large fraction of the gas remains trapped and therefore the "effective" pore volume for liquid flow is reduced. When the gas and the ASP solution are co-injected, the oil is mostly produced in emulsion form as gas enhances mixing of the in-situ fluids. Trapped gas could lead to an efficient oil recovery, depending on the amount of trapped gas: the lower the trapped gas saturation the better the oil recovery.
- Europe > Netherlands (0.28)
- Asia (0.28)
Microemulsion Flow in Porous Media: Implications for Alkaline-Surfactant-Polymer Flooding
Humphry, K. J. (Shell Global Solutions International) | Van Der Lee, M.. (Shell Global Solutions International) | Ineke, E. M. (Shell Global Solutions International) | Van Batenburg, D. W. (Shell Global Solutions International) | Southwick, J. G. (Sarawak Shell Bhd)
Abstract Workflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present. Alkali-surfactant-polymer flooding (ASP) is an EOR technique under consideration for a number of Malaysian oil fields. In ASP flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media. Here, preliminary measurements of microemulsion rheology are presented. Large volumes of microemulsion, with and without polymer, are generated using model alkali-surfactant (AS) and alkali-surfactant-polymer (ASP) systems. These microemulsions are studied using conventional shear rheology. The viscosities measured using a conventional shear rheometer indicate microemulsion viscosities higher than either the AS(P) solution or decane from which they are comprised. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. In situ viscosity measurements in Berea sandstone indicate apparent viscosities 1.5 to 6 times larger than those measured in a conventional shear rheometer. The implication of these results for ASP flooding is discussed.
- North America > United States > Texas (0.46)
- North America > United States > West Virginia (0.46)
- North America > United States > Pennsylvania (0.46)
- (2 more...)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
Enhanced Oil Recovery by Chemical Flooding from the Biostromal Carbonate Reservoir
Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Wang, Zhe (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Wu, Kangyun (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Hou, Qingfeng (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Long, Hang (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC)
Abstract Lab study of chemical EOR for the carbonate reservoir was performed through core characterization, chemical formula screening, surfactant adsorption losses experiments and oil displacement core flooding tests of chemical flooding. The research results lay the foundation of future pilot tests for chemical combination flooding applying to carbonate reservoirs. Core characterization by scanning electron microscope and mercury injection capillary pressure experiment prove that there are plenty micropores and a few emposieu within rock, porosity of formation cores is relatively high but permeability is low, the reservoir lithology belonged to typical biostromal carbonate reservoir and the heterogeneity is severe. Chemical flooding formula was investigated by polymer and surfactant screening tests. Salt tolerant polymers including STARPAM and KYPAM showed good viscosifying performances than conventional polymer when prepared with formation water. Amphoteric surfactant AS-13 and anion-nonionic surfactant SPS1708 were selected and ultra-low interfacial tension between crude oil and formation water can be obtained in alkali-surfactant-polymer (ASP) and alkali free surfactant-polymer (SP) systems. Adsorption losses of surfactants on core sample showed that the dynamic adsorption losses of surfactant AS-13 and SPS1708 were 0.46mg/g and 0.37mg/g respectively. Core flooding tests of chemical flooding proved that more than 17~18% incremental oil recovery over water flooding could be obtained with ASP (0.6wt% Na3PO4 + 0.3wt% surfactant + 1000ppm polymer) or SP (0.3wt% surfactant + 1000ppm polymer) flooding. The effect of both ASP and SP flooding was better than that of surfactant flooding. The experimental results are considered to be technical feasibility and confirm the effectiveness of chemical EOR methods especially the SP flooding for the biostromal carbonate reservoir, which may present further understanding for chemical EOR field application in carbonate reservoirs.
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Yibal Field > Yibal Khuff Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Yibal Field > Sudair Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- (2 more...)
Enhance Heavy Oil Recovery by In-Situ Carbon Dioxide Generation and Application in China Offshore Oilfield
Jia, Xiaofei (CNOOC Ltd.-Tianjin) | Ma, Kuiqian (CNOOC Ltd.-Tianjin) | Liu, Yingxian (CNOOC Ltd.-Tianjin) | Liu, Bin (CNOOC Ltd.-Tianjin) | Zhang, Jing (CNOOC Ltd.-Tianjin) | Li, Yanlai (CNOOC Ltd.-Tianjin)
Abstract Miscible/Immiscible carbon dioxide injection is considered as one of the most effective technology to improve oil recovery from complicated formations. Main factor restraining wide application of this technology is its dependence on natural CO2 sources, transportation of CO2, breakthrough of CO2 to production wells, corrosion of well and field equipment, safety and environmental problems etc. However, in-situ carbon dioxide generation technology is eliminating CO2 negative impact and strong control of the process. The EOR mechanism of proposal technology is described as follows: acid and exothermic chemical reaction function relieve deep reservoir damage, micronucleus systems formed possess abnormal reological properties allowing to improve water flooding efficiency, CO2 as a super-critical fluid decreases oil viscosity and gas form CO2 reaches such place in the formation where not many solvents can enter to, foamed gas-liquid system creates additional resistance for water injected after gas-liquid system, surfactant formed decreases interfacial tension in oil-water contact, and CO2 solved in oil increases oil volume what affects on displacement of residual oil. Lab research shows that proposed technology can decrease injection pressure of damaged core by 11.7MPa, gas generation amount and oil volume increasing rate increases with temperature and system concentration increasing, oil volume increasing rate and oil viscosity reducing rate increasing with oil viscosity increasing. Under the conditions of 60 degrees Celsius, 10MPa, 2010mPa.s, it can increase oil volume by 25%, reduce oil viscosity by 52.7%, improve recovery efficiency by 7.6%~14.2%. Field pilot tests were conducted in seven injection wells in China Bohai offshore oilfield in 2009~2010. All the wells present significant effect of decreasing injection pressure and increasing injection rate, average decreasing pressure by 3.2MPa, average increasing injection rate of single well by 22118m, cumulative increasing injection rate by 154827m, cumulative increasing oil of around production wells by 29000m. Field pilot tests shows that proposed technology can be applied in a wide range of geological conditions, and be the key to recovering huge amount of oil from highly watered, depleted, heterogeneous and other type of so called hard-to-recover oil reserves.
- Asia > China (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.46)
Abstract Prior to any EOR application, quantifying the remaining oil saturation (ROS) after water flood is critical in order to establish the target oil for a potential EOR scheme. The most widely available datasets for quantifying ROS are from the saturation logs such as resistivity logs from infill wells and pulsed neutron capture (PNC) logs from cased wells. However, the interpretation of these logs generally requires prior knowledge of water salinity. In most water flood projects, the injected water is different from the formation water, and the salinity is unknown in the water flooded zones. Logging tools for saturations without prior knowledge of salinity, such as the C/O log, also have limitations. The current practice to overcome this problem is to apply one or more of the following techniques: • Log-injection-log • Chemical tracer • Sponge coring, pressurized coring, etc. However, these techniques are relatively expensive and time-consuming. They cannot be used routinely field wide as a reservoir surveillance tool. In this paper, we present a methodology to reduce the uncertainties in saturation logs within the context of reservoir model history-matching. In addition to matching pressure and water cut, the new methodology seeks to match the produced water chemistry too (with formation water and injection water chemistry as inputs). This is due to the recent advance of reservoir simulations that can model reservoir water composition changes by considering geochemical reactions of injection waters, formation brine, and reservoir minerals. With this new simulation capability, resistivity and sigma values per grid block are computed as part of the simulation, thus pseudo-logs of total resistivity and neutron capture cross section (S) can be generated as part of the simulation. This enables direct history-matching of the measured log signals. For an EOR project, the implication of this new simulation methodology is to encourage the frequent sampling and analysis of injection and produced water as part of the reservoir surveillance, and run resistivity and/or S logs to monitor saturation changes even when injection water is significantly different from formation water.
Abstract Factors confronting the application of surfactant flood in high temperature, high salinity carbonate reservoirs include: high concentration of divalent ions in the formation brine, the stability of the surfactant in high thermal environment, surfactant adsorption on carbonate rock fabrics and the effect of high salinity and brine mineral composition on the multiphase system, typically encountered in carbonate reservoirs. For preliminary screening purposes, thermal stability, salinity tolerance and emulsification characteristics are given importance, while the capacity to alter the wettability of the reservoir rock towards a water-wet system is desired. Several surfactants were screened based on their abilities to address issues of high thermal environment, high salinity effects and capacity to create a water-wet environment. A series of akyl-polyglucoside (APG) surfactants were studied which are established as eco-friendly, renewable, nontoxic and bio-degradable surfactant and one of them found to be suitable for the target carbonate reservoir. An unique approach adopted during the screening process for thermal stability was the analysis of the UV-visible light absorption profile of the surfactants after subjecting them to reservoir condition for specific periods. The APG showed salinity tolerance up to 263,000 ppm at 220 oF. During phase study divalent ions are seen to have considerable impact on the nature of microemulsion (middle phase). Incremental recovery between 19-15% was observed for surfactant flood after secondary waterflood and spontaneous imbibition of aqueous phase was enhanced in the presence of surfactant solution. The recovery was correlated with microemulsion phase behavior and wettability alteration.
- North America > United States (0.47)
- Asia > Middle East > UAE (0.28)
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.97)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.97)