bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Visualisation of Chemical EOR Flooding Using a Lab-on-a-Chip Setup Supported by an Extensive Rheological Characterisation
Authors: Wegner J.. , Hincapie R. E. , Födisch H.. , Ganzer L.. 
Published: August 2015

Abstract
Two phase polymer flooding experiments were carried out using a novel Lab-on-a-Chip experimental set up. The microfluidics device uses porous Glass-Silicon-Glass (GSG) micro-models which were constructed based on reservoir rock thin section. The model attempts to resemble the thin sections internal porous structure geometry but also the rock wettability. The results were monitored and analyzed in real time using an image analysis algorithm.
Polymer flooding is widely used to obtain incremental oil recoveries through providing favorable mobility ratio. However, its ability to mobilize and displace oil at microscale through its viscoelastic properties is still debated. EOR flooding experiments performed in micromodels that resemble porous media provides continuous visual access that combined with quantitative image analysis can provide improved understanding on displacement mechanisms. In particular, the more difficult questions concerning the complex viscoelastic behavior of polymers and its role in mobilizing trapped oil. In addition, when verified, micromodel based flooding can provide a complement to experimentation on limited core samples.
The experimental results did not show a significant increase in oil recovery due to viscoelasticity in the micromodels used at the preset experimental conditions. GSG micromodels were successfully implemented under reservoir temperature for flooding experiments. Additionally it was found that using an extended Cox-Merz Plot (relation between Rheological parameters) to describe the rheology will improve the interpretation of the phenomena taking place; as well as considering the elongational rheology of aqueous polymer solutions.
The results presented in this work show that flooding experiments in micromodels have a great potential to improve chemical EOR screening processes. The visualization technology depeloped during this work will contribute significantly and can be the enabler of intensified application of microfluidics technologies in EOR.
Visualization of In situ Microemulsion Phase
Authors: Unsal E.. , Broens M.. , Buijse M.. , Boersma D.. , Makurat A.. , Armstrong Ryan T. 
Published: August 2015

Abstract
In situ formation of microemulsions is studied by co-injection of its individual phases: surfactant solution and decane oil. The experiments were conducted in micro-channels etched on a glass micromodel which facilitates the direct observation of the microemulsion formation. The micromodel was horizontally placed under an inverted fluorescence microscope. The aqueous phase was injected via one micro-channel and the oil phase was injected via another. The two microchannels merged at a T-junction where the microemulsion phase started forming upon mixing of its two individual phases. The oil phase was doped with an oil-soluble fluorescent dye, called Nile Red, which shifts its fluorescent peak based on the polarity of the environment. Under fluorescent light, the microemulsion and oil phase fluoresced bright red and amber brown, respectively.
Microemulsions found their application in chemical enhanced oil recovery (cEOR) due to their ability to eliminate the capillary forces by generating ultra-low interfacial tension (IFT) between the aqueous phase and the oil-in-place. The flow regime shifts from immiscible to a quasi-miscible one, allowing the brine to access the more isolated parts of the rock. Inevitably the microemulsion becomes part of the flowing system and it has to be recovered. Therefore understanding of the microemulsion rheology as well as its IFT is important. The common knowledge on microemulsion formation is limited to the phase behavior analysis performed in static test tubes. Such tests answer some questions on microemulsion properties once they are formed, but they do not provide any insight to how a microemulsion forms and flows.
This study presents a methodology to visualize the microemulsion together with its aqueous and oil phase components at the time scale necessary to study mixing. These visualizations can provide insights into questions regarding in situ microemulsion formation, and consequently, the rheological behavior of multiphase systems with ultra-low IFT. Our experiments indicated that at flowing conditions the fluids may mix spontaneously, and the mixing profile depends on the salinity of the environment as well as the injection rates.
Discussion on the First N2-SAGD Pilot Test in China
Authors: Erpeng Guo , Youwei Jiang , Yongrong Gao , Hongzhuang Wang , Pengbo Yu 
Published: August 2015

Abstract
Injection of non-condensable gas into steam chamber during SAGD (Steam Assisted Gravity Drainage) process is a widely adopted method to improve the efficiency of heavy oil recovery. In Liaohe oilfield, China, a non-condensable gas injection pilot test was initiated since 2011.
This paper describes the operation history of the first N2-SAGD pilot test in China and gives an integrated evaluation based on the field data and history matching results for the first time. The effects of N2 injection was discussed by comparing the production dynamics before and after N2 injection. The steam chamber development process was analyzed on the basis of accurate history matching of production dynamics.
The production dynamic analysis shows that the result of the pilot test was very promising. After N2 was injected, the oil steam ratio increased by 80% with the oil production being enhanced by 20%. Also the water-cut decreased gradually. The results of analysis of steam chamber development indicates that, upon N2 injection, the vertical growth rate of steam chamber is decreased by 30~40%, whereas steam chamber volume expansion rate is increased by 7 times. At the same time the steam chamber grows more steadily and more lateral-preferentially. With N2 injection the life-cycle of SAGD process can be prolonged by 6 years with improved recovery.
The results of this paper show that non-condensable gas injection is an effective method in adjusting the development of steam chamber and improving the efficiency of the whole recovery process. Also this paper could serve as an enlightenment for the exploitation of similar heavy oilfields in China.
Foams with Ultra-Low Interfacial Tensions for an Efficient EOR Process in Fractured Reservoirs
Authors: Chevallier Eloise , Tchamba Oceane , Chabert Max , Bekri Samir , Martin Frederic , Gautier Serge 
Published: August 2015

Abstract
We both evidence a new formulation for ultra-low IFT foams and a new coreflood set-up to demonstrate the efficiency of such a formulation in a model fractured reservoir.
In fractured oil-wet carbonates reservoirs, recovery of oil from the matrix is limited by preferential flows in fractures, and the low permeability and wettability of the matrix. Injection of foams with ultra-low interfacial tension (IFT) may handle these challenges. On the one hand, foam can induce fluid diversion from the fractures to the matrix. On the other hand, ultra-low interfacial tensions with oil (&lt; 10−2 mN/m at optimal salinity) greatly enhance the oil recovery as demonstrated by ASP (Alkali Surfactant Polymer) floodings in homogeneous reservoirs. Ultra-low Ift values can efficiently decrease the entry pressure drop of oil-wet cores. Thus we here investigate the injection of foam with ultra-low IFT properties to mobilize oil in the poorly-swept matrix of oil-wet fractured carbonates.
First, obtaining both ultra-low IFT and stable foams in the same conditions is very often contradictory. Even a foaming solution with a domain of low-IFT generally exhibits a drop of foamability at the vicinity of the ultra-low IFT conditions. This study highlights a key criterion to obtain simultaneously both properties. The formulation requires an outstanding solubility (very low absorbance) at the vicinity of the ultra-low IFT domain. This condition is hardly encountered at the optimal salinity for common surfactant formulations and requires a wide screening of surfactants. From this criterion, we developed a mixture of surfactants which demonstrates simultaneously (60°C, 80g/L NaCl) a good foamability, foam stability and an ultra-low IFT with a crude oil.
Second, we present here a new coreflood set-up - called WFR after Waterflood Fractured Reservoir - designed to model foam flows in fractured reservoirs. The foam is pre-formed by co-injection of nitrogen gas and surfactant solution in a glass bead pack. The foam continuously washes the upper end-face of a vertical core sample. This geometry simulates a foam flowing in a fracture. The resulting flows generated in the matrix and the low-IFT values gives a total oil recovery of 93% OOIP.
The efficiency of the designed ultra-low IFT foam formulation is for the first time evaluated with this set-up to model representative conditions of a fractured system, and gives promising results.
EOR Enhancement Potential Analysis for One Oilfield
Authors: Pang Wei , He Zuqing , Wu Qiong , Hou Qian 
Published: August 2015

Abstract
Girasol oilfield is the first oilfield of Mansarovar Energy Colombia Ltd. (MECL) employing horizontal wells. With first well drilled in 2004 and commercial development started in 2008, this typical heavy oilfield have been produced for 10 years, but the current recovery factor is only 5.09%, and that is much lower than that of similar oilfields.
Girasol oilfield is at the medium stage of the cyclic steam stimulation (CSS) with 5.3 cycles and remaining reserves of 40.54 MMbbl. Based on characteristics of typical mid-shallow inter-bedded reservoirs with heavy oil in Girasol oilfield, by applying methodology of reservoir engineering and numerical reservoir simulation, the development status of Girasol oilfield is analyzed through full utilization of the geologic, logging and production performance data, and etc. Five potentials for production enhancement are researched including (1) Potential for well pattern improvement: except layer A12 and A9-Upper, other layers exist 30%~70% of uncontrolled regions in transition part between vertical and horizontal wells, nearboundary, low permeability areas; (2) Potential for well infilling: the well spacing is about 150m, while heating radius is about 50m, so there exist oils hard to exploit between wells. Numerical simulation shows the average heating area is only 33.07%. (3) Potential for CSS parameter optimization: compared with other similar blocks, the steam injection parameter is not suitable and the steam injection intensity is too low, and there is a good potential for optimized steam injection parameters; (4) Potential for horizontal lateral optimization: the current horizontal lateral of 600m on average is too long for thermal production because it will leads to high heat loss, un-uniform steam adsorption and poor steam injection effect; (5) Potential for steam flooding: as the reservoir geological conditions meet the screening criteria of steam flooding reservoir, there is a good potential for converting of steam flooding from CSS.
This paper constructs a framework and technical route for fullfield EOR enhancement design of heavy oil reservoir from potential analysis, sector simulation to fullfield scale implementation. Comparison of injection parameters and production performance among similar reservoirs in different countries is another highlight.
A Comprehensive Mathematical Model for Estimating Thermal Efficiency of Steam Injection Wells Considering Phase Change
Authors: Gu Hao , Li Chunlan , Cheng Linsong , Huang Shijun , Lin Menglu , Xiong Wenxue 
Published: August 2015

Abstract
Improving thermal efficiency of steam injection wells is an important goal in the process of steam injection for heavy oil recovery. The main objectives of this paper are to establish a comprehensive mathematical model for estimating the thermal efficiency of steam injection wells and to make some suggestions on how to achieve the above goal.
The mathematical model is composed of four sections. The first one is about prediction of thermophysical properties of injected steam considering phase change. In this section, if wet steam is not cooled to liquid water, slippage between gas and liquid phases is taken into account in calculating pressure drop based on momentum balance principle. In addition, a complete expression for steam quality distribution in wellbores is derived in detail. However, if phase change occurs, we can obtain an implicit equation for fluid temperature by combining energy balance and Coulter-Bardon equations. In the second section, steady-state heat transfer inside the wellbore and transient radial conduction in the formation are coupled at the cement/formation interface, based on which the wellbore heat loss rate is determined. Next, the thermal efficiency is estimated by using both direct and indirect methods. Finally, the mathematical model is solved iteratively for each segment and a detailed calculation flowchart is also provided.
The proposed model is validated by comparing simulated steam pressure, temperature and quality with measured field data from Liaohe Oilfield, and the direct and indirect methods of estimating the thermal efficiency prove to be reliable. Then, using the validated model, we analyze the effects of wellhead steam quality, injection rate and thermal conductivities of insulation materials on thermal efficiency of steam injection wells. The results indicate that enhancing the wellhead injection rate and using low thermal conductivities of insulation materials can greatly improve the thermal efficiency. But it is not a good choice to achieve this goal by improving the wellhead steam quality. Moreover, the paper shows that our methods for estimating the thermal efficiency of steam injection wells can also be applied to concentric-dual tubing steam injection wells.
In this paper, the comprehensive mathematical model for estimating the thermal efficiency of steam injection wells may be worthy of more attention, because it has not been widely reported in the literature. More important, phase change from steam/water two-phase flow to liquid water single-phase flow in deep wells is also considered in our study.
Application of Well Test Information to Judge Blocking and Channeling in Polymer Flooding Unit
Authors: Lin Jiaen , Qiu Kuntai , Guo Xiaoqun 
Published: August 2015

Abstract
Polymer flooding has been extensively applied to oilfields as an effective method for EOR, but along with injected time growing, some wells' bottomhole pressure rose up and oil production dropped, and the formation pressure rose while the reservoir was blocked, and water production of the other wells increased while the reservoir was channeled. An analytical method based on well test analysis is developed to incorporate well test pressure data with production data to verify whether the polymer flooding plays a role in displacing oil into wellbores.
Based on the non-Newton polymer well test analysis models to consider the polymer non-Newton effect, this paper employs two well groups located in Shuanghe polymer flooding pilot unit of Henan Oilfield by using the dynamic performance analysis approach in which the well test information is combined with the production data to judge the blocking and channeling. First qualitative analysis is performed to compare different period pressure history curves of the different period pressure test data by drawing Cartesian coordinate charts and log-log diagnosis charts of pressure change and its derivative of all the well test data with production history data for a well. Secondly we interpret all the well test data from the two well groups with 6 periods' well test data to obtain the formation parameters by using non-Newton fluid well test analysis software.
Blocking and channeling could be judged qualitatively and quantitatively by correlating different period pressure trend and production data trend charts and parameters from the different period well test interpretation. For blockage, oil production flow rate dropped, the formation pressure rose and wellbore skin factors increased for production wells, and reservoir permeability decreased. For channeling effects, both production flow rate and water cut increased, but the formation pressure almost did not change and reservoir permeability did not change. To recognize the geological characteristics and production condition of the two well groups based on the above ideology, Non-Newton composite models with two zones is chosen to analyze the tested wells to acquire the skin factor, internal and external zone flow capacity, internal area radius, formation pressure. Since skin factor and formation pressure increase, both internal and external area zone flow capacity reduce, and internal area radius becomes smaller. It is concluded that the areas around the tested wells have been blocked.
Most innovative aspect of the methodology developed in this paper to judge blocking and channeling effects of polymer flood reservoir in a systematic fashion is by contrasting different periods of tested pressure change trend, flow rate change trend and production water cut change trend with the parameters obtained by non-Newton fluid well test analysis to get a more direct solution of resultant lower uncertainty.
Low-Tension Gas Modeling in Surfactant Alternating Gas and Surfactant/Gas Coinjection Processes
Authors: Beygi Mohammad R. , Varavei Abdoljalil , Lotfollahi Mohammad , Delshad Mojdeh 
Published: August 2015

AbstractIn this paper, we present a framework to model low-tension gas flood process and implement the model into the UT in-house compositional gas reservoir simulator (UT-DOECO2). A gas compositional model is coupled with microemulsion phase behavior to capture important mechanisms in hybrid gas-chemical flood processes in porous media.Two different surfactant molecules are simultaneously applied: one to lower interfacial tension to ultra-low values and one to keep foam stable as gas mobility control agent. This process cannot currently be modeled using the commercial reservoir simulators. We implemented the option for two surfactants into the existing gas compositional simulator with foam and hysteresis options. A predictive simulator would make it possible to select the best candidates for field application and tailor process design to particular characteristics of each field.In the field-scale application of the Surfactant Alternating Gas (SAG) process, multiphase fluid behavior in porous media is modeled using three-phase compositional relative permeability and three-phase hysteresis models to include both compositional and saturation history effects. These models represent a more-accurate prediction of the cycle-dependent properties of SAG. The gas entrapment in the foam flow is used to predict the hysteresis effect within each cycle using a dynamic Land coefficient. The in-situ foaming behavior is estimated based on the mechanistic foam models. This study, further, evaluates mobilization and displacement of residual oil in tight reservoirs using the low-tension gas flood and compares the results with other EOR options.Using a reliable multiphase simulator low-tension gas experiments can be scaled up to the field and to optimize chemical-gas EOR process design. Numerical simulation of the SAG with and without hysteresis is used to assess the effect of the gas-entrapment on oil recovery and gas utilization factor in a field-scale application.
ASP as a Brown Field Re-Development Opportunity - Based on a Case Study
Authors: Anand A.. , van Batenburg D.. , Parker A.. , Eikmans D.. , Boersma D.. 
Published: August 2015

AbstractPredicting Alkaline Surfactant Polymer flood performance at fullfield scale is an interestingly vast subject. Typically, this would comprise of detailed modelling exercises at different dimensions and resolutions to calibrate the model for observed physical and geo-chemical behavior during the fluid flow. Modelling of different physical and chemical phenomena active during the ASP flood offers different complexities. To name a few, the phenomena active during the ASP flood in a reservoir are changing salinity, changing interfacial tension, changing capillary pressure and relative permeability, viscosity modification, chemical transport and retention, residual resistance factor, shear effects and so on. Nonetheless, the degree of areal and vertical heterogeneity in the field has a significant imprint on the ASP flood as an effective recovery process and poses another hurdle in the flood optimization. Also, due to large number of variables associated with the ASP process itself, the number of uncertainty and design parameters increase tremendously in comparison to any conventional recovery technique. The large list of sensitivity variables with increased computational time to model ASP active processes, makes it further restrictive to carry-out a holistic sensitivity analysis.This paper investigates and addresses the aspects of a field scale development of an ASP flood with the help of full-fledged ASP modelling for our example field. The paper will cover the entire spectrum of the ASP feasibility study from illustrating the approach adopted to simulate the ASP active phenomena to the demonstration of the flood optimization techniques for the field. We will illustrate how the degree of areal and vertical heterogeneity in the field can cause inefficient utilization of chemicals, which in our case was found to have the most limiting effect on ASP field performance. We will discuss some of the ways to optimize the ASP flood in such a heterogeneous reservoir system. The selection of the uncertainty and design parameters and their ranges will be shown and the outcomes of the sensitivity analysis will be presented, including creaming curve analysis. We will also highlight the fullfield 3D effects on some of the conventionally established ASP parameters, for instance slug size.
Low-Tension Gas (LTG) Injection Strategy in High Salinity and High Temperature Sandstone Reservoirs
Authors: Nguyen N.. , Ren Guangwei , Mateen K.. , Cordelier P. R. , Morel D. C. , Nguyen Quoc P. 
Published: August 2015

Abstract
The work presented in this paper evaluates the potential of Low-Tension Gas (LTG) as an alternative to polymer flood for displacing the surfactant slug in a chemical EOR process in ultra-high salinity (above 189,000 ppm TDS), high temperature (above 85°C) sandstone reservoirs. The LTG process involves the use of surfactant and gas to achieve the mobility control required to displace the micro-emulsions and the crude oil. The optimal formulation of surfactants is identified to obtain good oil/water microemulsion phase behavior and desirable high optimum salinity. The latter feature allows the LTG process to work with a wide variation of injection brine salinity or in-situ salinity gradient. The optimal injection strategies are then determined through a series of oil recovery core floods with co-injection of gas and the surfactant solution. Tertiary recovery of up to 90% of the residual OIP was achieved for cores with 150–400md air permeability. The high optimum salinity that is closest to the formation brine salinity was found to give the highest incremental oil recoveries. Macroscopic stability of displacement fronts was studied via pressure derived mobility ratios. Approximate parity of relative mobility of injected fluids was observed with respect to relative mobility of displaced water at true residual oil saturation and interpreted relative mobility of a formed oil bank. These results indicate that in-situ foam propagation was present which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding. By replacing polymer with foam, chemical EOR methods can be expanded into formations where the use of polymer is impractical.