bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simultaneous Injection of Water and Polymer (SIWAP) to Improve Oil Recovery and Sweep Efficiency from Layered Carbonate Reservoirs
Authors: Masalmeh Shehadeh K. , Blom C. P. , Vermolen E. C. , Bychkov A.. , Wassing B.. 
Published: July 2011

Abstract
A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100.
The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs.
Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process.
Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study.
Selection of Investment Portfolios and Funding Options with Joint Ventures in Oil and Gas
Authors: Ndiaye M. M. 
Published: July 2011

Abstract
In Oil and Gas Industry, due to the high investment in projects, the long payback period and the high risk involved, selecting the best projects portfolio and ways to minimize risks are difficult challenges for decision makers. In addition finding funding for the selected portfolio increases the complexity.
The process of selecting Project portfolios is a complex task, which passes through various stages until it reaches the point of selecting the optimal portfolio [Galeno, 2008]. To invest in a project, companies look for its own available investments capital, banks, markets, and partners in Joint Venture.
This paper presents a framework for portfolio selection with Enhanced Oil Recovery (EOR) projects funding option including Joint Ventures, based on the Markowitz model.
The methodology is applied to a set of four projects in oil and gas business. The outputs with risk exposure are compared to risk-free using Markowitz models. The results show that the framework with the risk management models can be used for EOR portfolio selections with funding option and for joint venture equities determination.
Investigation of Different I-WAG Schemes Toward Optimization of Displacement Efficiency
Authors: Mousavi Mirkalaei S. Mousa , Hosseini S. Javad , Masoudi Rahim , Ataei Abdolrahim , Demiral Birol M. , Karkooti Hooman 
Published: July 2011

Abstract
The success of the hydrocarbon recovery improvement via Water Alternative Gas injection process is closely related to the microscopic displacement and macroscopic sweep efficiency. Effectiveness of the successive displacements by water and gas injections, maximizing the three phase zones by optimum force balancing in the reservoir, WAG injection cycle, double displacement and film drainage process are among the important parameters that affect the sweep and displacement efficiency in WAG process. Water and gas injection scheme play an important role in optimization of these parameters. Different schemes of WAG injection have been reported in open literature including gas injection up dip, water injection down dip and vice versa.
In this paper, the efficiency of various WAG injection schemes toward improvement of the above important parameters will be presented. Detailed theoretical investigation and simulation study are conducted. A new injection scheme is proposed. In the proposed methodology, water is injected from down dip and gas is injected from up dip in the first cycle. In the second cycle, gas is injected from down dip and water is injected from up dip. Water and gas injection location will alternatively change in each cycle of injection. Different design parameters are considered and studied including mobility ratio between water and oil phases, location of the water and the gas injectors, injection rate, WAG injection cycle. The results show that the proposed methodology has significant improvement on the displacement efficiency and three phase zone size and hence yield higher hydrocarbon recovery.
17 Years Development of Artificial Lift Technology in ASP Flooding in Daqing Oilfield
Authors: Yang Yonghua , Zhou Wanfu , Shi Guochen , Gang Cao , Wang Guoqing , Sun Chunlong , Qiang Li , Zhao Yunlong , Zhao Changming , Bai Wenguang , Wu Miao , Li Yanfei , Zhang Ming , Li Jinling , Ma Zhiquan , Xu Wenlin 
Published: July 2011

AbstractTo date, ASP flooding has been applied in commercial test in Daqing Oilfield for 17 years. From the beginning of the test, scaling issue in downhole artificial lift equipments had been realized as one of the most difficult problems in ASP flooding which resulted in high pump failure rate and operation cost. Therefore, the scaling principle in producers was studied in order to create a scaling risk analysis and risk prediction mechanism. In addition, Based on numerous laboratory study and field trial, a series of anti-scaling artificial lift techniques were developed as well, including surface material modification technique, special pump design, chemical scaling remover, etc.Due to the considerable diversity of scaling phenomena in different blocks, different period and different wells, the anti-scaling artificial lift strategy was required to be adjusted respectively. Consequently, an innovative anti-scaling artificial lift methodology was created for different ASP flooding areas in Daqing Oilfield. This methodology was applied in 102 wells, both in beam pumping wells and PCP wells. The averaged running lives of artificial lift systems were improved from less than 30 days to over 300 days.This paper detailed the developments of innovative artificial lift technology in ASP flooding in Daqing Oilfield. These new developments will effectively propel the commercial application of ASP flooding in petroleum industry.
Reservoir Characterization and Estimation of Remaining Oil Saturation using NMR logs for Optimizing a CO2 Flood: A Pilot Study
Authors: Ramakrishna Sandeep , Murphy Eric , Balliet Ron , Sullivan Lonnie , Barclay Kathleen , Schutte Raymond 
Published: July 2011

AbstractReinvestment in, and the rejuvenation of, aging oil fields are becoming increasingly commonplace. Because the price of oil has stabilized at an equitable value and enhanced oil recovery methods have been proven, previously-depleted oil reservoirs are being revisited to determine their potential for tertiary recovery by means of CO2 flooding. Accurate determinations of unswept oil and permeability distribution within the reservoir are critical elements in understanding and optimizing the CO2 flood. This paper presents a pilot study in utilization of NMR logging in the redevelopment of a field that has been waterflooded since 1953.These mature reservoirs pose well-known challenges for formation evaluation. Resistivity-based saturation models are inadequate and uncertain because of previous waterfloods and variable formation water salinity (Rw) values. The variations in grain size and the onlapping of sand bodies cause uncertainty with the use of a porosity-permeability transform to estimate permeability.These challenges must be overcome for optimal well placement, infill drilling, CO2 flood design, and other reservoir management practices. The standard logging suite for newly-drilled wells, triple combo and nuclear magnetic resonance (NMR), has evolved to address many of these challenges.This paper presents a pilot study that demonstrates the effectiveness of NMR logs for reservoir characterization. These reservoirs were evaluated for estimating formation porosity, bound and moveable fluid volumes, permeability, and remaining oil saturations. The log data were compared and calibrated with X-ray diffraction (XRD), Specialized Core Analysis (SCAL), and Capillary Pressure data from core. Pore-size distribution from NMR has been used to identify facies changes and for geomodeling purposes. Variations in the facies and the distribution of the sand bodies have been correlated to 3D seismic data. This has helped with the accurate mapping of the reservoir units to understand sweep efficiency. Production results are used to validate the log interpretations. A similar method can be used in other aging oil fields and to evaluate the development plan of a CO2 flood.
Direct Visualization of Designer Water Flooding in Model Experiments
Authors: Cense A. W. , Berg S.. , Jansen E.. , Bakker K.. 
Published: July 2011

Abstract
Increasing oil production by injection of designer water – also known as low salinity water – into a reservoir has recently attracted substantial attention from the oil producing community. The phenomenon has been studied by many researchers and low salinity water flooding is currently being applied in the field. On a macroscopic level, the effect can be parameterized as effective wettability modification to a more water-wet state but on a microscopic level, the effect is still not very well understood.
Most researchers agree that in sandstone rock, the mechanism is related to clay minerals but most of the experimental evidence is provided on the macroscopic scale (core flooding experiments) or even the field scale. Observations are not fully consistent and the predictability of the effect is limited. In a preceding publication [Petrophysics 2010, 51(5), 314–322] direct experimental evidence was provided for the detachment of oil droplets from a clay substrate upon exposure to low salinity brine.
The brine salinity for designer water flooding falls within a narrow window of opportunity: when too high, no additional oil production is observed; when too low, clay swelling and/or deflocculation may result in formation damage in the field. This raises the question whether there is a regime where oil is released with no or only minor formation damage and what the optimum salinity level for this would be. In this follow-up study, experiments are conducted on montmorillonite clay (which is a swelling clay belonging to the group of smectite clays) where the amount of released oil and the degree of formation damage are studied as a function of the salinity level. Starting at very high salinity (26,000 mg/L totally dissolved solids, TDS) no release of oil was observed and the clays remained stable. At very low salinity (2,000 mg/L TDS), up to 30% of the oil was released accompanied by substantial formation damage. There is, however, an intermediate salinity regime between 6,000 and 15,000 mg/L TDS where the formation damage is only very minor or not visible at all and still 10-30% of the initially attached oil is released. This is the regime of interest for field applications, although salinity levels have to be evaluated for the type of clay present in the formation rock.
Alkaline Steam Foam: Concepts and Experimental Results
Authors: Lau Hon Chung 
Published: July 2011

Abstract
Experimental studies have shown that the steam foam process can be significantly enhanced by injecting a suitably formulated alkali-surfactant mixture in the aqueous phase of steam. Emulsion screening tests, corefloods and flow visualization experiments using an alpha olefin sulfonate (AOS) surfactant with 16 to 18 carbon, Na2CO3 and a heavy Californian crude have shown that alkaline steam foam offers significant advantages over regular steam foam by combining the benefits of thermal and chemical enhanced oil recovery (EOR) processes.
Firstly, Na2CO3 reduces surfactant consumption by adsorption by rendering the clay surface more negatively charged. Secondly, by precipitating divalent ions that get ion-exchanged off the clays, Na2CO3 reduces surfactant consumption by precipitation. Thirdly, a suitably formulated alkali-surfactant system reduces the oil-water interfacial tension (IFT) sufficiently to enable the heavy oil to be emulsified into the aqueous phase in the presence of steam. This oil-in-water emulsion is less viscous than that of the oil and can be readily transported. Consequently, the residual oil saturation is reduced to that below steam. Fourthly, this lower residual oil saturation reduces the destabilizing effect of oil on foam resulting in stronger steam foam that provides better mobility control than regular steam foam. Therefore, it has the potential to further reduce steam gravity override. Fifthly, the reduction in gravity override also reduces loss of heat to the cap rock. Steam utilization is thereby improved.
When applied to steam drive, cyclic steam soaks and steam-assisted gravity drainage (SAGD) processes, alkaline steam foam has the benefits of increasing foam propagate rate, improving mobility control, improving steam utilization and reducing the residual oil saturation. In the cases of steam soaks and SAGD, it also increases the gravity drainage rate of oil by reducing the effective oil viscosity through emulsification.
An Alternate Simplified Approach For Selecting Enhanced Oil Recovery Technologies Using Analogs And Hubbert Peak Theory
Authors: Ortiz Volcan Jose Luis , Blanco Ronelba Isabel , Djotaroeno Diane Sirikit 
Published: July 2011

AbstractSelecting the optimum combination of enhanced oil recovery (EOR) technologies is a critical activity during preparation of a successful business plan. This is usually accomplished by using protocols with technical parameters at reservoir formation levels from which candidates EOR technologies are screened and then subject to investment and risk assessment evaluation for final decision by management.The previous approach very often misses the effect of operational expenditures, wearing and failure related downtime and learning curve during pilot testing on oil recovery efficiency and EOR economics which is usually expressed in terms of net present value.This paper proposes an alternate simplified approach using an acceptable representation of life cycle phases of natural and physical asset components functioning as a system of assets for a particular subject reservoir. We introduce a taxonomic solution to help in classifying candidates EOR technologies. Four major functional indices are used for handling uncertainties and risks using data from analogs for defined scenarios in the subject reservoir: 1-Accesability) Footprint effects for constructing and operating physical assets (wells and surface infrastructure), 2-Contactability) Volume of resources contacted from a surface location, 3-Produceability) Volume of producible resources from drainage area to surface and 4- Effectiveness) Combined effect of availability, reliability, maintainability y and capability in efficiency of oil recovery.The four major indices are cross referenced with life cycle cost (LCC) and estimated ultimate recovery (EUR) using Hubbert peak oil theory and the Petroleum Resources Management System classification for resources and reserves. Uncertainties and risks are modeled with Monte Carlo simulation (MCS) or Systems Dynamics (SD) depending on the complexity of the system of assets.We present examples using synthetic data to illustrate the method.This approach is worth using during EOR project definition and planning as an alternate to complex data hungry methods.
A Case Study: A Successful Steam Flooding Project to Enhance Oil Recovery of Low-permeability, Light-oil Waterflooding Reservoir
Authors: Wu Shuhong , Han Min , Ma Desheng , Wu Yongbin , Yu Qian , Chunli Yao , Dehuang Shen 
Published: July 2011

Abstract
Steam flooding, one of commercial technologies widely used to develop heavy oil reservoir, has brought reservoir engineer’s attention to improve performance of waterflooding, light oil reservoir and enhance its oil recovery. In Cy reservoir of Daqing oil field, a steam flooding project is successfully going on to enhance the oil recovery after waterflooding. Cy reservoir is a typical low-permeability, light-oil reservoir with depth of 1000m, an average permeability around 8 md and a typical porosity of 16%, oil viscosity of 16~95mpa.s.
Cy reservoir came into development in 1995 under waterflooding. However, waterflooding has suffered from low water injectivity, poor sweep, and poor injector-to-producer communication. Only 10% of oil in place has been produced during 10 years’ waterflooding. In 2007, steam flooding was utilized to improve the performance and enhance the oil recovery. The steam flooding project shows promising results. The response to steam injection is prompt and significant. The injectivity is doubled and productivity is almost tripled. The oil-steam-ratio is around 0.3. The incremental recovery is predicted to be over 10%.
The paper will firstly brief production history of waterlfooding. Secondly, the paper will detail steam injection and analyze its performance and influence factors.The paper will also discuss mechanisms, strategies as well as barriers and difficulties to high recovery of steam flooding in such waterflooding, light oil, low permeable reservoir andl also detail reservoir engineering study, such as development manner, injection and production system, and its physical and numerical simulation. The steam flooding project shows us that steam injection has great potential in improving injection and production profiles, increasing productivity and enhancing oil recovery.
Numerical Simulation Study of SAGD Experiment and Investigating Possibility of Solvent Co-Injection
Authors: Ashrafi Mohammad , Souraki Yaser , Karimaie Hassan , Torsaeter Ole , Kleppe Jon 
Published: July 2011

Abstract
Bitumen resources constitute a high portion of the total world oil resources. The main recovery mechanism for these high viscous fluids is to reduce their viscosity by the application of heat, mostly by introducing steam.
Among different steam injection schemes, steam assisted gravity drainage (SAGD) has become the method of choice applicable to bitumen and oil sand reservoirs. In these extra heavy oil resources, the reservoir has almost no injectivity due to high oil viscosity, and therefore conventional steam flooding is hard to conduct. SAGD, however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well and is then being produced. Recently hybrid processes are attracting more attentions in the industry. These processes benefit from co-injection of a solvent together with steam. The solvent can diffuse into the bitumen and make it even lighter by reducing the viscosity.
Our simulation study is based on the experimental work done by Chung (1988) and the simulation model of this experiment by Chow (1993). Chung’s physical experiment was a 2-D model to simulate SAGD experiment in laboratory. The Chung’s experiment was done with Cold Lake crude oil. A reservoir simulation model was built using a numerical thermal reservoir simulator. The model was then tested and validated with Chung’s physical model. Having a valid model, sensitivity analysis was run to examine the effect of different simulation parameters on recovery and steam oil ratio.
The sensitivity parameters tested are steam temperature and quality, the porosity of the model, different well placement schemes, and the effect of shale barrier. Different steam temperatures and qualities were examined. The best injection condition was found to be 130 °C and 90% quality, beyond which no increased recovery was achieved. Different injector and producer placements were tested. Placing injector and producer diagonally in the model showed the best horizontal sweep efficiency in the laboratory model. Horizontal shale barrier had a dramatic negative effect on the oil recovery. Vertical shale, however, had a smaller effect. This is because in horizontal case the steam chamber cannot reach to the top layers. Porosity was found to be inversely proportional to the oil recovery and steam oil ratio. Results showed that solvent can help to improve oil recovery and steam-oil ratio. In addition most of the injected solvent could be recovered from production stream. Sensitivity analyses on solvent type and concentration indicated significant effects on performance of process. Among the solvents used in this study, hexane showed the best recovery performance.
An Integrated EOR Successfully Applied In Chang-6 Ultra-Low Permeability Reservoir
Authors: Guo Xiao , Yang Yue 
Published: July 2011

Abstract
The Chang-6 reservoir is characterized by low porosity, ultra-low permeability and low Deliverability. At present, water injection pilot only occupied 3.6% of the whole reservoir area. Most of wells will been flooded rapidly once water injection was conducted. How to enhance the oil well production and crude oil recovery is of great strategic significance for guaranteeing the sustained and sTab.le development of YanChang oil field Co.ltd. In this paper, a series of empirical formula was compared and oil recovery of Chang-6 reservoir was determined at 13.9%. The starting pressure gradient and stresssensitive experiments were carried out. The result suggested that the influence of stress-sensitive cannot be ignored. Based on infiltrating fluid experiments and considering the stress sensitivity, a comprehensive research of numerical simulation for the injection zone was conducted to determine the residual oil saturation and demonstrate the feasibility of cyclic water injection, continuous water injection and surfactant injection for EOR. In addition, a suit of clean-fracturing fluid of surfactant acting agent was invented and a foam fluid system was optimized for Chang6 low-permeability reservoir. This study and pilot show that invented clean-fracturing fluid and optimized foam fluid system was effective for ultra-low permeability reservoir.