bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Isenthalpic Multiphase Flash Calculations for Thermal Compositional Simulators
Authors: Heidari M. , Nghiem L. X. , Maini B. B. 
Published: June 2014

Abstract
In thermal compositional reservoir simulators that use energy as a primary variable, thousands to millions of isenthalpic multiphase flash calculations must be performed to calculate temperature, phase splits and compositions for different grid blocks during the simulation. Development of a robust and fast isenthalpic multiphase flash calculation method is necessary to improve the efficiency of such simulations.
A new isenthalpic multiphase flash calculation is described in this paper. The flash calculation method uses a modified Rachford-Rice monotonic objective function and the negative flash concept for phase distribution and phase identification. Therefore phase stability analysis is not necessary. The formulation and algorithm of the new method are presented in detail. This method is able to handle difficult situations such as narrow boiling point regions and phase appearance and disappearance, which are dominant in thermal processes. The current method encounters no difficulty in the latter situations unlike stage-wise isenthalpic flash calculation methods.
After the accuracy of new method was compared and verified against current algorithms used by the industry, it was also tested for robustness and speed. The results show promising performance compared to the current methods. This proposed method is not sensitive to the initial guess for temperature. As a matter for fact, in all of the test cases in this study, the same temperature was used as the initial guess. A poor initial guess for temperature only requires more iterations to reach the solution.
Forward Modeling of SAGD-Induced Heave and Caprock Deformation Analysis
Authors: Shen Luyi , Singhroy Vern , Samsonov Sergey V. 
Published: June 2014

Abstract
This study focuses on the investigation of the mechanism behind surface heave induced by thermal recovery. Injection of steam into oilsand reservoirs results in changes in temperature and pore pressure within the subsurface. These changes can induce a reduction of effective stress, which provides initial containment of bitumen. Irreversible shear/tensile deformation of the caprock and overburden might be one of the unwanted consequences of such process.
We developed a work flow incorporating the Finite Difference Method (FDM) and Finite Element Method (FEM). Heat and fluid flows are computed using FDM with CMG-STARS and elastic/plastic deformation estimations are done through Abaqus FEM simulation software. The Mohr-Coulomb yield criterion and the non-associated flow rule is used to assess the plastic failure in the reservoir and caprock. This work flow is used to assess the impact of the SAGD process on the integrity of caprock.
The geomechanical model is calibrated with surface deformation measurements. Parameter search is performed to study how geomechanical parameters influence the expression of reservoir deformation at the surface. The uncertainty associated with the modeled results shows the need for a more refined geomechanical model, considering the heterogeneous nature of geological structure in the region of interests.
The Effects of Minerals on Heavy Oil and Bitumen Chemistry When Recovered Using Steam-Assisted Methods
Authors: Montgomery Wren , Sephton Mark A. , Watson Jonathan S. , Zeng Huang 
Published: June 2014

Abstract
The production of gaseous sulfur-containing species during the steam-assisted recovery of heavy oil and bitumen have important consequences for both economics and safety. Factors such as the effects of mineral matrices require laboratory data to produce accurate models. To study mineral effects on gas production we studied a well-characterized oil-containing core and the isolated crude oil from that core. The samples were run at 250–300°C in the continued presence of liquid water for 24 hours. The reaction products of all experiments include gases, oil flotate, oil sinkate, water-soluble products, and water-insoluble residues. All reaction products were studied with a variety of analytical techniques, including FTIR spectroscopy, chromatographic fractionation (SARA analysis), GC-MS, pyrolysis GCMS and GC-FPD/TCD. These techniques were applied to whole oil, maltenes and asphaltene fractions. Physical properties including viscosity and density were also measured. Our data provide insights into the physical and chemical consequences of steam assisted recovery of heavy oils and bituments from sedimentary rock reservoirs and reveal that geological and geochemical context is an essential consideration.
ESP Optimization in an Extra Heavy Oilfield: A Case Study in Colombian Llanos Basin
Authors: Lopez Uribe J. , Jiménez Morales G. 
Published: June 2014

AbstractThe experience of working with extra-heavy oil producing wells profitably requires the use of available technologies to the limits of their capabilities. Due to its heavy use of electricity, the Electrical Submersible Pump (ESP) has often proven unsuitable for fields producing high-viscosity fluids. However, in some cases, given the conditions downhole and fluid behavior, along with technological changes, it has been possible to use ESPs at moderate cost.Exploitation today has become technically and economically feasible for reservoirs in upper or lower layers that were previously uneconomical given lifting, transportation and marketing costs.Previously discovered resevoirs in the Llanos Basin of Colombia were considered of no commercial value given the characteristics of its oil (higher viscosities to 1,000 cps at 60° F /14.7 psia and API gravities less than 10°). The Operating Companies of the same blocks discovered other, more easily exploited oil reservoir units. These oilfields, now in their mature stages, have high production costs because of the inevitable increase in water cut and/or decreased pressure. This has spurred to the use of existing infrastructure and advances in technology for lifting, processing and transportation of heavy and extra-heavy oil reservoir units already discovered.There have been several challenges in developing extra-heavy oil wells, such as organic precipitation, presence of scales, strong emulsions and high GOR.ESP technology has advanced in the extraction of large fluid volumes, smaller stage diameters, metallurgy resistant to corrosion and abrasive solids, stronger shafts, and conditions of high pressure and high temperature. However, there are very few developments in sustainable extraction of heavy oil and extra-heavy oil.This article describes an example of implementing the Electro Submersible Pump as a feasible method for artificial lift in wells producing extra-heavy oil.
Evaluation of Artificial Lift Modes for Heavy Oil Reservoirs
Authors: Mali Prasanna , Al-Jasmi Ahmad 
Published: June 2014

Abstract
Exploitation of heavy oil fields in Kuwait Oil Company (KOC) has been a challenging task. Both, cold and thermal methods are planned to produce these fields judiciously. Crude oil API gravity is 10-12. Well depth is from 700 to 3000 feet. Expected variation in production rate is from 30 - 300 bbl/d for cold production. With thermal application, envisaged range of liquid production rate is from 100 – 1000 bbl/d. Therefore, it is important to evaluate different artificial lift modes, to produce these heavy oil fields.
In this regard, application of various artificial lift modes, such as PCP, SRP, ESP, ESPCP, Metal PCP, etc., which can be used to produce heavy oil fields, under cold and/or thermal production pattern, are studied and are outlined in this paper.
With regard to this feasibility study, for cold heavy oil production, pilot of conventional PCP technology is carried out. Liquid rates of 30 - 300 bbl/d are achieved, when PCP technology, is tested for few wells, for cold heavy oil production. For heavy oil thermal production, pilot of ‘Metal PCP’ technology is carried out, with cyclic steam injection in place. Peak liquid production rate of 460 bbl/d is achieved, when metal PCP technology is tested in one well. The paper describes pilot methodology of these pilots. Results of both these pilots are encouraging. This has resulted in planning to use both these technologies, to produce heavy oil fields, on large scale basis.
Thus, the paper can be used as reference, to evaluate different lift technologies to produce heavy oil fields. It is inferred from the feasibility study that conventional PCP and metal PCP are emerged as desirable lift technologies, to produce heavy oil fields. Successful pilot implementation of these technologies, has further justified utility of these technologies, for exploitation of heavy oil fields.
Nitrogen Foam Anti-Edge Water-Incursion Technique for Steam Huff-Puff Wells of Heavy Oil Reservoir With Edge Water
Authors: Wang Jiexiang , Wang Tengfei , Yu Yingjun , Chen Zheng , Niu Zhiwei , Yang Changhua 
Published: June 2014

Abstract
The cyclic steam stimulation is an important thermal recovery technique which is used to develop heavy oil reservoirs. However, the development effectiveness is limited in steam huff-puff wells of heavy oil reservoir with edge water because of the sharply increased water cut caused by the incursion of edge water. An experimental device, which can simulate edge water and steam stimulation process, was designed on the basis of steam flooding device to investigate the nitrogen foam anti-edge water-incursion technique. The designed device includes 3 subsystems: reservoir physical simulation subsystem, edge-water simulation subsystem and fluid injection subsystem. The effect factors and application conditions of the technique were investigated, and the results showed that the effect of the technique was influenced by reservoir water-flooded degree, edge water energy and crude oil property significantly. This technique is more suitable for seriously water-flooded reservoirs whose cycle water cut is no less than 80%, and the reservoir edge water energy and heavy oil viscosity should be moderate. As for Henan heavy oil reservoir, the optimum edge water pressure is 4MPa, and the oil viscosity is less than 5000mPa·s at the reservoir temperature (stock tank oil). The optimum injection pattern of the technique is N2 slug – nitrogen foam slug – steam. Pilot tests were conducted based on experimental results. The operation success rate is 100%, the average cycle water cut is reduced by 23%, and the average cycle oil production is increased twice. In view of the test result, this technique is a successful measurement to inhibit the water incursion and enhance the oil recovery of steam huff-puff wells with edge water.
Evaluating the Importance of Geomechanical and Reservoir Properties When History Matching 4D Seismic Data in SAGD Wells
Authors: Hiebert Allan , Pathak Varun , Lifshits Gary , Kumar Anjani 
Published: June 2014

Abstract
It is becoming increasingly common to use 4D Seismic surveys on SAGD projects to characterize the steam chamber size, shape and growth. The use of this type of survey in history matching SAGD simulation models has also grown significantly, allowing engineers to match not only the volumes, temperatures and pressures, but the shapes of the steam chambers as well. In the authors' experience, however, before 4D Seismic surveys can be used confidently to history match the steam chamber shapes, we need to understand what 4D seismic represents. Prior proposals suggest steam or gas chamber volume, stress change volume or temperature change volume. To investigate this, the current study examines the impact of various physical property changes impacting the surveys (in particular, geomechanical effects), so that the appropriate 4D seismic history matching criterion are established.
To determine how the above factors impact the 4D seismic surveys, this study investigates the relative impact of various property changes that occur in-situ during the SAGD process, with the intent to determine what changes have the biggest impact on seismic velocity. A number of SAGD simulation runs were conducted using typical oil sands geology with fully coupled geomechanics. Afterwards, the change in pressure-wave velocity and shear-wave velocity at the simulation grid blocks at various times during the simulation was calculated. The property changes of temperature, pressure, stresses, saturations and fluid properties were also calculated, and then categorized in terms of the significance each factor has to the 4D Seismic data. This categorization serves to identify the appropriate SAGD history matching criterion, to improve the quality, confidence and predictability of a SAGD simulation model.
Solvent-Assisted Start-up of SAGD Wells in Long Lake Project
Authors: Ahmadloo F. , Yang P. 
Published: June 2014

Abstract
In oil sands in situ operations using steam-assisted gravity drainage (SAGD), achieving effective communication between the injector and producer with a reasonable conformance is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction phenomena for establishing communication between the wells. For oil sands reservoirs containing extremely high viscosity bitumen, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 90 to 120 days to achieve. Start-up operation can be accelerated by enhancing the rate of convective heat transfer to the formation by techniques such as bullheading and cold/hot dilation.
At Nexen's Long Lake in-situ SAGD project, the use of higher injection pressures to enhance start-up is limited by the presence of high water saturation zones within the bitumen pay zone ("lean zones"), an adjacent Quaternary-age fresh water-bearing channel, and shallow formation depth. In order to overcome these constraints, an approach using solvent injection in a warm system with enhanced injectivity was successfully designed and implemented. In this approach, the solvent was injected in a high bitumen saturation system after circulating the well for about 70 days. Then, the solvent was chased with hot water into the formation to deliver the solvent deeper into the formation and enhance the rate of solvent-bitumen mixing during the soaking time.
This paper reviews the design criteria, well selection process, and implementation of warm solvent injection in the conducted pilot in the start-up phase of Pad 13 at Long Lake. It also compares production responses of solvent-treated and control wells with comparable reservoir properties within the same pad to evaluate the performance of the designed pilot. Review of the production data shows that the solvent-treated well pair has outperformed all the other well pairs of the pad with no apparent conformance issues. This well had a quick ramp-up which is considerably faster than the average ramp up time at the Long Lake project. The collected data suggests that applying solvent-assisted start-up in systems that have enhanced mobility by pre-circulation of steam can shorten the circulation time and accelerate the ramp-up phase after SAGD conversion.
A Systematic Approach for Inflow Control Devices Testing in Mackay River SAGD Wells
Authors: Becerra O.. , Kearl B.. , Sanwoolu A.. 
Published: June 2014

Abstract
Inflow control devices (ICDs) have been extensively used in horizontal wells for conventional oil and gas production in order to prevent early water break through or gas coning. The benefits associated with this technology have been studied with reservoir simulation and validated with field experience. Some of the benefits associated with ICDs that have been described in the literature are: easier well clean out during start up because the ICDs allow application of higher drawdown to poorly performing sections of the reservoir, higher recovery factor caused by delayed water break through or gas coning, uniform production contribution of the horizontal section, and better sand control by limiting the fluid rate per joint.
In theory, similar benefits can be achieved using ICDs in SAGD applications. In this case steam break through instead of gas coning could be prevented. If live steam production is mechanically controlled by the ICDs, bitumen from the colder sections of the production well can be produced by applying a higher drawdown. In this way the total bitumen production should be increased while steam oil ratio (SOR) is reduced. Nevertheless, the available drawdown between SAGD well pairs is very limited and the conventional design approach consisting of uniform flow along the horizontal section is not applicable.
To design an ICD completion trial at the MacKay River SAGD Project, Brion Energy has conducted studies involving theoretical analysis, segmented well simulation, technology evaluation, and equipment selection. The results of these studies indicate that higher cumulative production with lower SOR can be achieved when the ICDs are installed in bitumen production wells where the reservoir exhibits significant heterogeneities. However, the hot spots in the well have to be produced at zero wellbore sub-cool in order to generate a differential pressure capable of bringing colder sections of the well into production. The study also suggests that a further reduction in SOR can be achieved when the ICDs are also installed in the steam injection wells.
Phase Behaviour and Viscosity Reduction of CO2-Heavy Oil Systems at High Pressures and Elevated Temperatures
Authors: Li Xiaoli , Yang Daoyong , Fan Zhaoqi 
Published: June 2014

Abstract
Techniques have been developed to experimentally and theoretically determine phase behaviour and viscosity reduction of CO2-heavy oil systems at high pressures and elevated temperatures. Experimentally, vapour-liquid phase boundaries (i.e., saturation pressure lines) and the swelling factors are measured by conducting PVT tests at pressures up to 11094.0 kPa and temperatures up to 362.75 K, respectively. The viscosity of CO2-saturated heavy oil is measured at 319.15 K. Theoretically, the heavy oil sample is respectively characterized as a single- and multi-pseudocomponent(s). An exponential distribution function is used to split the plus fraction of heavy oil up to C105+, while a logarithm-type lumping method is used to group the single carbon numbers (SCNs) into multiple pseudocomponents. Then, the Peng-Robinson equation of state (PR EOS) coupled with the modified alpha function is applied to quantify the phase and volumetric behaviour of the CO2-heavy oil systems. The binary interaction parameters (BIPs) for CO2-pseudocomponent(s) pair are tuned to match the measured saturation pressures. Compared with the characterization scheme of treating heavy oil as a single pseudocomponent, the absolute average relative deviation (AARD) for the predicted saturation pressures can be improved from 5.27% to 4.56% by characterizing the heavy oil as six pseudocomponents. With the optimum BIPs, the swelling factors are predicted by the PR EOS with and without the volume translation technique, respectively. It is found that the introduction of the volume shift to each (pseudo)component in the PR EOS is able to provide more accurate prediction in both characterization schemes with AARD of 1.88% (oil as a single pseudocomponent) and 1.39% (oil as six pseudocomponents), respectively.
Investigation of the Physical and Chemical Genesis of Deep Tar-Mat Oil and Its Recovery Potential under Different Temperatures
Authors: Almansour Abdullah , Al-Bazzaz Waleed , Saraswathy Geetha , Sun Yongpeng , Bai Baojun , Flori Ralph 
Published: June 2014

Abstract
Deep tar-mat layers, which occur between the aquifer column and the reservoir-oil column, contain substantial quantities of extremely heavy oil and are found in various parts of the world, most prominently in Middle Eastern nations such as Saudi Arabia, Qatar, south Iraq, and Kuwait. Tar mats are thick layers with oil gravity of less than 10 °API; they isolate conventional oil reservoirs from their aquifers either partially or completely, causing numerous problems when applying oil recovery technology. However, in this study, tar mats are considered as a potential source from which to extract difficult oil. Researchers have attempted to experimentally evaluate the effect of toluene, hot water, and surfactant solution extractions on several carbonate tar-mat rock samples at several different temperatures (25°C, 135°C, 225°C and 315°C). In the study presented in this paper, samples were selected from a tar-mat carbonate reservoir in Kuwait. The physical and chemical geneses of tar-mat oil were analyzed utilizing several experimental geochemical techniques, such as rock evaluation pyrolysis, liquid extracts for Saturates, Aromatics, Resins, and Asphaltenes (SARA analysis), and elemental fingerprinting of Carbon, Hydrogen, Nitrogen, Sulfur, and Oxygen (CHNSO). These geochemical techniques were integrated in order to quantitatively evaluate the tar-mat recovery patterns of the carbonate reservoir at different temperatures. The results showed that the oil recovery significantly increased as the temperature increased. A comparison of all three methods indicates that for light and heavy tar mats, toluene produced the highest oil recovery at all temperatures tested, reaching as high as 47.1% at 315 °C. The surfactant treatment yielded less oil recovery than toluene, which reached as high as 7.5% at 315 °C. The temperature had a significant effect on light tar-mat oil recovery when using water methods; the oil recovery reached as high as 6.2% when using water at 315 °C. However, high-temperature water had little effect on extremely heavy tar mats. The paper provides a systematic method by which to quantitatively characterize tar-mat crudes in carbonate reservoirs.
Correlation of Permeability and Volume of Shale in Oil Sands: Improving Predictability in Low Permeability Zones of the McMurray Formation, Alberta, Canada
Authors: Dabek Les , Shad Saeed , Abdinia Ali Dalir , Knepp Rex 
Published: June 2014

Abstract
The Lower Cretaceous McMurray Formation of Alberta, Canada, contains vast quantities of bitumen. Oil sands hosting this bitumen were deposited and reworked by tidal and fluvial currents, resulting in heterogeneous sediment distributions comprising cross-stratified and massive sands, breccias, and low permeability sand- to mud-dominated inclined heterolithic stratification (IHS). Conventional reservoir characterization workflows suggest that reservoir permeability correlates most closely to volume of shale (vShale). One aspect of such workflows is derivation of an empirical correlation between permeability obtained from core analyses and calculated vSh from wireline logs. While there may be numerous direct measurements from core samples, uncertainty in oil sands reservoir permeability is known to result from preferential sampling of clean sands versus muddy IHS and from scale differences between core sample and well log resolution. This uncertainty is particularly significant in facies with permeability &lt; 500 millidarcy. We integrated multi-scale exploration data from a producing McMurray Formation reservoir to demonstrate the impact of centimeter-scale reservoir architecture on permeability. The study uses high-resolution 3D models of the near-wellbore region to characterize observed variability in percentage, orientation and dimension of mud laminae, breccia clasts and trace fossils. We created multiple realizations to capture the variability in model simulation parameters. High-resolution models of several million cells were upscaled at the resolution of the vSh log using a flow simulation-based numerical method. Upscaling results are estimates of effective directional permeability (kx, ky, kz). The flow-based permeability results better define the interrelationship of permeability and vShale within a reservoir. Our results demonstrate a modeling workflow that provides more precise permeability estimates at wireline log resolution. This workflow has the potential to improve history matching in flow simulations and improvements in well placement and performance forecasting.