bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymer Solution Injection – Near Wellbore Dynamics and Displacement Efficiency, Pilot Test Results, Matzen Field, Austria
Authors: Clemens Torsten , Deckers Marie , Kornberger Martin , Gumpenberger Thomas , Zechner Markus 
Published: June 2013

Abstract
A number of reservoirs in the Vienna Basin in Austria might benefit from polymer solution injection. In November 2011, a Polyacrylamide polymer injection pilot commenced for the 8th Torton Horizon reservoir to reduce the uncertainties related to this technology.
To further improve the understanding of the polymer solution injection, laboratory experiments and numerical simulations were performed.
The results of the injection test and laboratory experiments show that two phases can be distinguished: first, a phase of polymer solution injection below the Formation Parting Pressure (FPP) can be observed. This phase is characterised by high flow velocities in the near-wellbore area, resulting in severe degradation of the polymer, and a slower rise of the pressure than expected for undegraded polymers. In the second phase, the FPP is reached and fractures are generated. In this phase, the polymer solution exhibits shear-thinning behaviour in the fractures. Owing to significantly lower flow velocities in the formation, degradation of the polymers is limited. Phase one is usually short in comparison to phase two.
To achieve sufficient polymer solution injection rates for an economic project without degrading the polyacrylamide polymer, inducing fractures by injection is required for the reservoirs in the Vienna Basin. Hence, screening of fields has to include geomechanical properties of the reservoir sands and surrounding shales. Also, the risk of fracturing outside of the formation has to be assessed. In addition, the values of the FPP of the reservoir sands and surrounding shales and the direction of induced fractures should be determined. Furthermore, the injection water quality in terms of fines and oil content has an impact on the fracture growth and should be evaluated.
Cyclic Hysteresis of Three-Phase Relative Permeability Curves Applicable to WAG Injection under Low Gas/Oil IFT: Effect of Immobile Water Saturation, Injection Scenario and Rock Permeability
Authors: Fatemi S. Mobeen , Sohrabi Mehran 
Published: June 2013

Abstract
One major problem in the numerical simulation of the water-alternating-gas (WAG) process is the uncertainty associated with the changes in three-phase relative permeability (kr) values in the sequence of drainage and imbibition cycles known as cyclic hysteresis. In this work we have investigated the effect of cyclic injection of water and gas on three-phase kr of water, gas and oil under both water-wet and mixed-wet conditions. Two different sandstone cores with one order of magnitude difference in absolute permeability (65 mD and 1000 mD) have been used in the coreflood experiments.
In the base study, WAG injection started with water flooding (I) followed by gas injection (D) and this cyclic injection was repeated three times (IDIDID). To investigate the effect of immobile water saturation, the IDIDID injection scenario was repeated with lower immobile water saturation. To study the effect of saturation history, another WAG experiment was performed which started with the primary gas flooding (D) followed by water injection (I) and this cyclic injection were repeated as DIDIDIDI. For all of the experiments, three-phase relative permeabilities were obtained analytically from the coreflood data using an extension of Buckley-Leveret formula to three-phase flow.
The results show irreversible kr hysteresis loops for water and gas and saturation history dependency for oil in processes involving cyclic injection under three-phase flow conditions. Generally, krg reduced during successive cycles for all WAG experiments. For the IDIDID injection sequence and in water-wet system, it was found that krg shows larger hysteresis effect for the case with higher immobile water saturation. krw hysteresis was larger in the DIDIDIDI injection scenario compared to the IDIDID case. krg and krw hysteresis effects were larger for the 1000 mD core compared to the low permeability (65 mD) sample. The most important hysteresis effect for both krg and krw was observed for the transition from two-phase to three-phase. As WAG cycles were repeated, krg and krw hysteresis reduced became minimal after the 2nd water injection in IDIDID and 2nd gas injection in DIDIDIDI injection sequences.
Comparison of our experimental observations with predication of existing models highlights some serious shortcomings of reservoir simulators in simulation of oil recovery processes involving three-phase flow and flow reversal. The paper also offers some novel insights into cyclic hysteresis behaviour and offers explanations based of our understanding of the pore-scale and core-scale displacement mechanisms involved in three-phase flow and WAG injection.
Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated with H2S into Depleted Gas Fields in Northeast Netherlands
Authors: Bolourinejad P. , Herber M. A. 
Published: June 2013

Abstract
Depleted gas fields are amongst the most probable candidates for subsurface storage of CO2. With proven reservoir and qualified seal these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine due to formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and cap-rock. Thus, for adequate, safe and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. In order to investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30 days) laboratory experiments on reservoir and cap-rock core samples from gas fields in northeast Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream (H2S) in these fields.
The injected gases were CO2, CO2+100 ppm H2S and CO2+5000 ppm H2S. Before and after the experiments the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. Also the permeability of the samples was measured. Following the experiments, dissolution of feldspars, carbonates and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S in the CO2 stream. Firstly we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection where dissolution of anhydrite was dominant in the samples. Secondly, severe salt precipitation took place in the presence of H2S. This is caused by the higher solubility of H2S in water and a higher water content of gas phase in the presence of H2S. This was confirmed by modeling using CMG-GEM (CMG, 2011) modeling software.
The precipitation of salt, anhydrite and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and &lt;3%, respectively. In caprock samples permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5000 ppm H2S the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, salt precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.
Studies and Pilot Project on Steam Stimulation with Multiple Fluids for Offshore Heavy Oil Reservoirs
Authors: Xu Wenjiang , Chen Zhangxing , Shan Jincheng , Sun Yongtao 
Published: June 2013

Abstract
Steam flooding and stimulation processes have proven to be the most promising method for commercial in situ recovery of heavy oil. For high quality and thick oil reservoirs, these processes can achieve oil recovery of over 30% OOIP. However, for thin, deep and offshore oil reservoirs, they are uneconomic due to excessive heat loss to overburden and great requirement to heat the reservoir rock.
A new process, Steam and Multiple Fluids (SMF), is being developed to improve efficiency of the steam stimulation process for offshore heavy oil reservoirs. It involves the addition of non-condensable gases to the injected steam. Injected gases accumulate in the region away from the well and lower the temperature. Only the region’s temperature near the well is close to the temperature of steam. Heat loss to the overburden and the heat requirement to heat reservoir rock can be significantly reduced due to the lower temperature requirement. Considerable saving can be achieved from reduction in quantity of steam required for the process.
This process is studied by using laboratory experiments and numerical simulations via a 3D thermal model for an offshore heavy oilfield. The results show that, compared to the cold production and standard steam stimulation processes, the oil rate from SMF is the highest. The application of this process makes production of offshore heavy oil economic and should extend the range of reservoirs that can be produced economically. A pilot test for calibrating this new process is reported.
An Enhanced Oil Recovery Technology as a Follow Up to Cold Heavy Oil Production with Sand
Authors: Coskuner Gökhan , Naderi Khosrow , Babadagli Tayfun 
Published: June 2013

Abstract
Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required.
Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and under burden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent.
This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky's Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent.
It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.
Understanding HW-CSS for Thin Heavy Oil Reservoirs
Authors: Chang Jeannine 
Published: June 2013

Abstract
This paper evaluates the potential of applying horizontal well CSS (HW-CSS) technology to enhance heavy oil production from non-CHOPS thin pay resources in the Iron River/Manatokan area. Thin non-CHOPS heavy oil and oil sand deposits are a considerable resource. The economics for thermal operations in these deposits are hampered by the fact that they contain less oil over producing horizontal wells than do thicker deposits.
A numerical model was built and simulations were performed to answer the questions: Can HW-CSS be developed to exploit "non-CHOPS" thin heavy oil resources?What is the cut-off pay thickness for an economic application of HW-CSS?How can HW-CSS be used to maximize the net present value (NPV) of oil recovery from thin heavy oil resources?
The initial simulation results indicated that despite a determined effort to develop optimized operating strategies, HW-CSS cannot economically recover heavy oil when the reservoir pay thickness is less than 8 m due to excessive heat loss to the overburden/underburden. Later simulations demonstrated that the cut-off pay thickness for an economic HW-CSS process is around 11 m. With an optimized operating strategy and well spacing, and short well life, a cumulative steam-oil ratio (CSOR) under 6 m3 cold water equivalent (CWE)/m3 oil was achieved. The estimated oil recovery ranged from 30 to 50% depending on the well spacing used in the estimates (either 100 m or 75 m). For a 25 year project involving the installation of a new 8 well pad every 8 years, the internal rate of return (IRR) was estimated to be in the range of 20 - 25%.
For a 1 m reduction in pay thickness (e.g. from 11 to 10 m), the cumulative oil production/m of pay thickness decreased 6 - 8% when the reservoir pay thickness was less than 11 m, decreased 1 to 2 % when the reservoir pay thickness was between 11 and 17 m, and decreased less than 1% when the reservoir pay thickness was greater than 17 m.
The reservoir pay thickness of 14 m displayed the most efficient oil recovery for the reservoir pay thicknesses investigated (5 m to 20 m) although 20 m pay thickness resulted in the highest oil production. Thicker pays had a greater tendency for steam to rise because of an increased gravitational influence resulting in reduced lateral expansion. These pays required smaller well spacing for maximum oil recovery.
Better reservoir conditions such as higher permeability and lower oil viscosity generally achieved better performance. However, for reservoir pay thicknesses of 5 m and 8 m, an initial dead oil viscosity of 30,000 mPa.s resulted in lower oil recovery than having an initial dead oil viscosity of 50,000 mPa.s. The reservoir with 30,000 mPa.s viscosity oil displayed faster pressure and temperature dispersion resulting in ineffective use of the dilation and dead oil re-compaction mechanism.
An Empirical Correlation of Steam Chamber Size and Temperature Falloff in the Early-Period of SAGD Process
Authors: Zhu Lijuan , Zeng Fanhua , Su Shi , Wu Meng 
Published: June 2013

Abstract
Steam Assisted Gravity Drainage (SAGD) is a widely-used thermal oil recovery technique in western Alberta's oil sands reservoirs. Because of reservoir heterogeneity, the wellbore hydraulics and undulation, non-uniform steam chambers will evolve. Numerical simulation allows for the practical prediction of steam chamber size in SAGD. However, the long computational time in 3-D scenarios and the impact of uncertainties in input parameters limit its application.
In this paper, an empirical correlation between steam chamber size and temperature falloff data during shut-in time was developed in the early period of the SAGD process which is before the moment that the steam chamber starts spreading laterally. The temperature falloff responses and the corresponding steam chamber sizes at different locations in the producer along the lateral were obtained though 3-D numerical simulation studies. Based on the simulation results, an empirical correlation among steam chamber, the temperature falloff rate and the height of liquid level in the producer was derived through regression analysis. The same correlation equation with different coefficients was also found at different shut-in times. Therefore, the proposed correlation is general and can be applied in different reservoirs at different shut-in time during the early period of SAGD process.
The applicability of the proposed empirical correlation in estimating steam chamber sizes along horizontal well is also investigated and validated. Synthetic case study shows that the chamber sizes obtained from the empirical correlation and from simulation are in good agreement and suggests that this empirical correlation can be used to estimate the chamber size distribution along the horizontal well at the early period of SAGD process.
Physicochemical Properties of Bitumen and Solids from Grosmont Carbonate Cores
Authors: Angle Chandra W. , Dabros Tadeusz 
Published: June 2013

Abstract
The Grosmont and Nisku carbonate formations combined contain more than 25% of Alberta's crude bitumen on the basis of initial in-place volumes, making carbonates a significant potential source of bitumen in Alberta. About 400 billion barrels of bitumen is estimated to be located in the Upper Grosmont units1. We have studied seven cores from increasing depth in the formation. X-Ray diffraction data of core particles showed pervasive dolomitization and only minor differences were observed in trace clay and calcites. The cores with trace clay and calcite impurities appeared to have the highest bitumen content. Dean-Stark analysis of four selected cores sub-samples revealed that bitumen contents ranged from 5.84 to 15.4 wt%, with negligible water present in the as-received samples. Photoacoustic Fourier transform infra red spectroscopic analysis (FTIR-PAS) of core solids surfaces before and after the bitumen was extracted showed minor differences among surfaces of the particulates from Upper Ireton (UIR) to Upper Grosmont carbonate (UGC). The organics coatings, not visible by the naked eye, were revealed earlier by fluorescence microscopy and from these previous studies showed how solubility in water was affected.2 Asphaltene contents of bitumens extracted from the cores were all higher than for typical Athabasca oilsand bitumens. Bitumen viscosities measured as a function of temperatures using a falling ball viscometer and a rotational rheometer with plate-plate geometry at constant low shear indicated small differences among the bitumen samples and between the dolomitic bitumens compared to oilsands and SAGD bitumens studied before. Arrhenius fits gave activation energies within experimental errors for the two methods used. Densities measured as a function of increased temperatures were above those of water and varied among samples.
Characterizations on Geomechanical Properties of Colorado Shale Based on Well Logging and Laboratory Testing
Authors: Li Biao , Wong Ron 
Published: June 2013

Abstract
Geomechancial properties of shale are essential to drilling operation and well design for thermal enhanced oil recovery. In this research, well logging and laboratory testing data are integrated to characterize the geomechanial properties of Colorado shale in Cold Lake area, Alberta, Canada. Density and sonic logs were applied to estimate the dynamic deformation modulus, Poisson's ratio, internal frictional angle, and cohesion strength. Gamma ray log is applied to estimate shale's clay content. Triaxial tests and confined torsion tests were conducted on samples to investigate transversely isotropic stiffness parameters and strength at quasi-static condition. The micro fabric characteristics of the clay shale were obtained from SEM images to investigate shale's intrinsic anisotropy. Correlations between geomechanical properties derived from well logging and laboratory testing were generated. Values of deformation modulus and Poisson's ratio derived from laboratory testing and well logging were correlated by introducing empirical coefficients. The anisotropic ratio in rock's Young's modulus is correlated to shale's clay content. The values of log-derived internal frictional angle are consistent with the laboratory tested values. The shale's clay content is found to be an important factor affecting the rock's strength.
Time-Dependent Proxy Modeling of SAGD Process
Authors: Fedutenko E. , Yang C. , Card C. , Nghiem L. X. 
Published: June 2013

Abstract
The present paper proposes the use of a time dependent proxy model with the goal of efficient prediction of the future production performance of SAGD operations from a limited number of reservoir simulations. The proposed model is shown to provide powerful means for developing learning functions from input-output relationships described by the reservoir dynamics entailed by multiple combinations of inputs and controls. A SAGD case with 3 well pairs is used to illustrate the approach. The workflow is organized as follows: The specified number of direct numerical simulations is run for the time horizon of ten years for the given reservoir. These simulations correspond to different combinations of the operational parameters sampled according to the Latin Hypercube Experimental Design (LHD).The time series of the simulated production performance (particularly: entire field Oil Production Rate SCTR, and entire field SOR Cumulative SCTR) are used to build the time-dependent proxy model which represents production performance as an output function of the operational parameters and time. This paper uses and compares the following interpolators in N+1- dimensional space (operational parameters and time): a) anisotropic Ordinary Kriging, b) linear regression with regularization, c) Radial Basis Functions (RBF) Network method. Note that the extension of these methods to include time as the independent variable is one of the significant contributions of this paper.The proxy model is then used to predict the production data for the given reservoir for any time period (even longer than 10 years) and any combinations of the operational parameters.The predicted data are compared with the actual simulation results for the same time period and the same combinations of the operational parameters to evaluate the prediction quality. It is shown that all three proxy models can be used as a light version of simulator to get the production results for any combination of operational parameters and time horizon with much less computational efforts.