bluuebunny/crossref_metadata_2025_split huggingface dataset:
Microvisual Investigation of Foam Flow in Ideal Fractures: Role of Fracture Aperture and Surface Roughness
Authors: Buchgraber Markus , Castanier L. M. , Kovscek A. R. 
Published: October 2012

Abstract
Foam as a gas-mobility control agent is successful in enhanced oil recovery processes. An emerging application of foam is to aid surfactant solution delivery for EOR in heterogeneous porous media. In fractured reservoirs, foam acts as a blocking agent slowing and redirecting the transport of the aqueous phase in high transmissibility fractures. Foam aids the imbibition of foamer/surfactant solution into the matrix blocks so that remaining oil is drained. The design of such foam treatments for fractured media is an important factor for economic as well as recovery success. In this work we investigate the behavior of foam flow in fractures at various foam qualities and liquid and gas velocities. Laboratory experiments with different fracture replicates etched in silicon micromodels were used. Micromodels allow real time observations of flow behavior with a microscope and provide a fracture geometry that is easily replicated. A plain smooth fracture with different apertures (40 μm and 30 μm), a fracture with variable smooth apertures (either 20 μm or 40 μm) arranged in a checkerboard pattern and a constant-aperture fracture with a rough face were used to observe pre-generated foam in terms of texture, pressure drop and flow behavior. Mobility reduction factors for a wide range of foam qualities and flow rates were analyzed. Measured pressure drops increase linearly with an increase in foam quality up to 90%. At qualities greater than 90%, mobility reduction is only slightly reduced further. In general, mobility reduction factors (MRF) of 10-600 times were measured for low to high quality foams, respectively. Additionally video footage of foam at micro and macro scale is used to tie rheology to bubble shape and size. Study results are useful as input for upscaling of the rheology of foam fractures and for ultimate use in reservoir simulations to design effective chemical EOR treatments for fractured media.
Experimental Investigation of Bitumen Recovery from Fractured Carbonates Using Hot-Solvents
Authors: Pathak V. , Babadagli T. , Edmunds N. 
Published: October 2012

Abstract
With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in Northern Alberta have been estimated to contain at least 300 billion barrels of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general, e.g., the Grosmont unit is known to possess a triple porosity system – matrix, fractures and vugs, based on core studies. The second problem is the fluid itself, which is highly viscous bitumen, immobile at reservoir conditions. To extract this bitumen from very heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot solvent experiments conducted on original Grosmont carbonate cores.
Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested to be just above the saturation line of the particular solvent.. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot solvent process were verified for Grosmont carbonates.
Laboratory Study of Velocity Variations during CO2 Flooding in Tuscaloosa Sandstone
Authors: Mohapatra Avinash , Rai Chandra S. , Sondergeld Carl H. , Richards Trevor 
Published: October 2012

Abstract
Surface seismic offers a promising technique to monitor CO2 flood fronts during enhanced oil recovery process. Changes in seismic signature have been observed with CO2 flooding but quantification of the seismic signature with respect to subsurface saturation is still in its infancy. This study is focused on quantification of the variation in seismic parameters (velocity and impedance) with the change in subsurface fluid type and saturation.
The results of a laboratory study are presented where velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) are replaced sequentially. All the experiments were performed at in-situ pressure conditions on plugs (Tuscaloosa sandstones) recovered from a well in a field currently undergoing CO2 flooding. The plugs used are characterized as fluvial (quartz~87%, clay~10%) and distributary channels (quartz~75%, clay~17%).
During brine flooding on dry samples, a decrease in P-wave velocity (~2%) was observed till 95% saturation and thereafter the velocity increases by 15% during the remaining 5% saturation. After attaining 100% brine saturation, oil was pumped to displace brine till irreducible water saturation was achieved. A linear drop of 4% in velocity was observed during this step. Liquid CO2 was injected to displace oil-brine system and a drop of 8% in P-velocity was observed. Associated changes in P-wave impedance due to change in pore fluid saturation are 25%, -5% and -8% respectively for the three flooding experiment. Biot-Gassmann modeling shows good agreement with experimental results for gas-brine and oil-brine system but not for liquid CO2 flooding.
4D seismic data set acquired over the same region is quantitatively interpreted based on these laboratory measurements.
Sourceless Neutron-Density Porosity Determination: Fit-for-Purpose Formation Evaluation with Significant HS&E Benefits
Authors: Gjerdingen Tore , Hilton Joseph , Bounoua Noureddine , Irani Farzad , Fulton Chuck , Rodriguez Rubi 
Published: October 2012

Abstract
Chemical radioactive sources are commonly deployed in logging-while-drilling (LWD) assemblies to measure formation bulk density and neutron porosity. These measurements are widely used in porosity evaluation, lithology determination, clay volume estimates and fluid identification. Deploying logging tools with chemical sources poses Health, Safety and Environment (HS&E) risks requiring specific procedures throughout the entire process of planning, logistics and execution of well construction. Obtaining similar, identically equal or better formation bulk density and neutron porosity measurements without chemical sources has many advantages, particularly from the HS&E perspective in both standard and high-risk developments.
Advances in LWD technology have enabled the neutron porosity measurement to be obtained by employing an electronic neutron generator instead of a chemical source. These electronic neutron generators have been used for many years in different wireline tools and are now also available in LWD tools. The bulk density measurement has, until recently, only been measured utilizing a chemical source. Recent developments use the gamma rays induced by the interaction of high-energy neutrons (from the electronic neutron generator) with the formation as an "in-situ" source for subsequent derivation of bulk density.
Studies of the sourceless neutron-gamma-density (SNGD) data acquired in 15 to 20 horizontal and vertical wells have shown the accuracy obtained is within the specified limits, as compared to the traditional gamma-gamma-density (GGD) data. The typical density differentials observed in these environments are in the 0.01 to 0.02 g/cm3 range, which results in a porosity and saturation "error" in the order of 0.002 to 0.004 V/V. This level of accuracy is probably acceptable in a number of applications (e.g., infill drilling in mature fields), but may not be acceptable in other scenarios (e.g., more complex lithologies, extremely tight reservoirs), unless the HS&E considerations are overriding.
The HS&E benefits are important to keep in focus as they have a direct human benefit through the entire process of equipment preparation, transportation, wellsite operation and potential bottomhole assembly abandonment. Associated with this there is also the economic benefits related to less rig time required for source handling, and the potentially large savings in a lost-in-hole (LIH) abandonment scenario, in the locations where this is applicable. All these different aspects, HS&E, financial and technical, associated with the SNGD system need to be evaluated from a holistic viewpoint to ensure the most appropriate, fit-for-purpose acquisition program is selected in each case.
SmartWater Flooding: Industry's First Field Test in Carbonate Reservoirs
Authors: Yousef Ali A. , Liu Jim , Blanchard Guy , Al-Saleh Salah , Al-Zahrani Tareq , Al-Zahrani Rashad , Al-Tammar Hasan , Al-Mulhim Nayef 
Published: October 2012

Abstract
In recent years, improved/enhanced oil recovery by tuning the ionic composition of injection water has attracted the attention of the petroleum industry, and currently deemed as new emerging research trend.
In view of research results for the last four years, we demonstrated in previous reports (SPE 137634; SPEREE Journal, vol. 14(5), pp. 578-593; SPE 143550, SPE 141082, SPE 154076; SPE 154077) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Similar potential has been confirmed also in the secondary recovery mode. For recovery mechanisms, research confirmed that the driving mechanism is wettability alteration of carbonate rock surface and can be attributed to surface charges alteration, and microscopic dissolution of anhydrite. In this paper, we present the results of two field trials conducted in a carbonate reservoir to demonstrate the SmartWater Flood potential.
Both field trials confirmed that in-house research results can be replicated at field scale. Injection of SmartWater revealed a reduction of ~7 saturation units in the residual oil beyond conventional seawater. Considering these field trials are the first-ever applications in carbonate reservoirs, they further provided another confirmation that SmartWater Flood has significant potential to be a new recovery method targeting carbonate reservoirs. A special type of single-well chemical tracer was used in these trials to measure the residual oil in the vicinity of the well following the injection of each water type. During all stages of field trials, careful QA/QC program was put in place to monitor variation in ionic composition in all injected or produced fluids and further insure optimum ionic composition of SmartWater slugs. Several field trials are planned to optimize the current process leading to a multi-well Demonstration Pilot to determine the impact on ultimate recovery and reserves.
Stimulated Shale Volume Characterization: Multiwell Case Study from the Horn River Shale: II. Flow Perspective
Authors: Ehlig-Economides Christine A. , Ahmed Ibraheem , Apiwathanasorn Sippakorn , Lightner Jacqueline , Song Bo , Vera Fabian , Xue Han , Zhang Yannan 
Published: October 2012

Abstract
Characterization of shale gas stimulation and production mechanisms is of paramount importance to continued horizontal well hydraulic fracture stimulation design and execution. This study integrates analyses of fracture calibration tests, hydraulic fracture treatments, production logs, pressure buildup and well interference transients, and long term production data to quantify hydraulic fracture extent, shale permeability, and the expected ultimate recovery.
The study includes integrated analysis of 16 horizontal wells drilled from a pad in two opposing directions with mostly uniform length and spacing. Uncertainties in the hydraulic fracture and formation properties are reduced through rigorous modeling with analytical and numerical models. Results enable critical analysis of the shale development plan.
Recommendations from this study offer insight on stimulation design modifications to yield improved well performance and increased recovery efficiency within the pad stimulated volume defined by the wells.
Closed-loop Feedback Control in Intelligent Wells: Application to a Heterogeneous, Thin Oil-Rim Reservoir in the North Sea
Authors: Dilib F. A. , Jackson M. D. , Mojaddam Zadeh A. , Aasheim R. , Årland K. , Gyllensten A. J. , Erlandsen S. M. 
Published: October 2012

Abstract
Important challenges remain in the development of optimized control strategies for intelligent wells, particularly with respect to incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model or ensemble of models used in the optimization capture all possible reservoir behaviors at the individual well and completion level. This is rarely the case. Moreover, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. We evaluate the benefit of using closed-loop control strategies, based on direct feedback between reservoir monitoring and inflow valve settings, within a geologically heterogeneous, thin oil-rim reservoir. This approach does not omit model predictions completely; rather, model predictions are used to optimise a number of adjustable parameters within a general direct feedback relationship between measured data and inflow control settings. A high-resolution sector model is used to capture reservoir heterogeneity, which incorporates a locally refined horizontal grid in the oil zone, to accurately represent the horizontal well geometry and fluid contacts, and capture water and gas flow. Two inflow control strategies are tested. The first is an open-loop approach, using fixed inflow control devices to balance the pressure drawdown along the well, sized prior to installation. The second is a closed-loop, feedback control strategy, employing variable inflow control valves that can be controlled from the surface in response to multiphase flow data obtained downhole. The closed-loop strategy is optimized using a base case model, and then tested against unexpected reservoir behavior by adjusting a number of uncertain parameters in the model but not re-optimising. We find that closed-loop feedback control yields positive gains in NPV for the majority of reservoir behaviours investigated, and higher gains than the open-loop strategy. Closed-loop control can also yield positive gains in NPV even when the reservoir does not behave as expected. However, inflow control can be risky, because unpredicted reservoir behavior also leads to negative returns. Moreover, assessing the benefits of inflow control over an arbitrarily fixed well life can be misleading, as observed gains depend on when the calculation is made.
Investigation of Anisotropic Mixing in Miscible Displacements
Authors: Adepoju Olaoluwa O. , Lake Larry W. , Johns Russel T. 
Published: October 2012

Abstract
Dispersion (or local mixing) degrades miscibility in miscible flood displacements by interfering with the transfer of intermediate components that develop miscibility. Dispersion, however, can also improve oil recovery by increasing sweep efficiency. Either way dispersion is an important factor in understanding miscible flood performance.
This paper investigates longitudinal and transverse local mixing in a finite difference compositional simulator at different scales (both fine and coarse scale) using a two-dimensional convection-dispersion model. All simulations were of constant mobility and density, first-contact miscible flow. The model allows for variations of velocity in both directions. We analyzed local (grid-block) concentration profiles for various miscible displacement models with different scales of heterogeneity and permeability autocorrelation lengths. To infer dispersivitiy we fitted an analytical two-dimensional convection dispersion model to the local concentration profile to determine simultaneously local longitudinal and transverse dispersivities. Streamlines of simulation models were traced using the algorithm proposed by Pollock (1988). To our knowledge this is the first systematic attempt to numerically study local transverse dispersivity.
The results show that transverse mixing, which is usually neglected in the one-dimensional convection dispersion model of dispersion, is significant when the flow direction changes locally as a result of heterogeneity. The computed streamlines, which highlight the variation in flow directions, agree with the computed transverse dispersivity trends. We find that both transverse and longitudinal dispersion can grow with travel distance and that there are several instances in which transverse dispersion is the larger of the two.
Often, the variations in the streamlines are suppressed (homogenized) during upscaling. This paper gives a quantitative and systematic procedure to estimate the degree of transverse mixing (dispersivity) in any model. We conclude that local mixing, including transverse mixing should be considered when upscaling a fine scale model for miscible displacement to ensure proper preservation of fine-scale sweep and displacement efficiency and ultimate oil recovery for miscible displacement simulations.
Continuous Incremental Reserves in an Oil Rim Marginal Field Development through Integrated Technical Initiatives and Technology Advancements
Authors: Masoudi Rahim , Karkooti Hooman , Othman Mohamad B. , Altunbay M. Mehmet 
Published: October 2012

Abstract
Oil rim reservoirs are commonly marginal reserves with challenging drive-systems with high development cost and, therefore, are commercially less attractive. Development evaluation of such complex fields with the conventional methodologies and technologies may result in unsuccessful scenarios. The studied field, located in offshore Peninsula Malaysia, is a marginal oil rim reservoir with the oil column less than 42 ft with limited oil-in-place. The field was initially evaluated as a challenging development and a non-commercial asset. However, the integration of various technical initiatives and applying new interpretive techniques turned the field into an attractive asset and reserves have been continuously upgraded since the field development started.
The field was undergone proactive phasing development and reservoir management with a fit-for-purpose monitoring plan. The development strategy with long horizontal wells (i.e., up to 2 km) and smart completion with inflow control devices was matured through the development phasing and well-by-well performance evaluation. Various tracer applications with the PLT campaign in the long horizontal wells pre/post water-breakthrough (WBT) were used to justify the long horizontal wells. Well placements relative to contact were progressively improved allowing the delay in WBT and increasing the RF. Production rate, draw-down and GI/GP were continuously optimized pre/post water/gas break-through. Simulation model incorporated robust modeling of flow dynamics of the oil intervals in the capillary transition zone and long horizontal wells with smart completion modeling using the segmented well approach.
The applied development strategies together with the proactive reservoir management made the field development as a record successful case in Malaysia. The recovery factor progressively increased from earlier 16% to 35% presently. In this paper, suggested workflow, guidelines and key tasks with the field data and the results are presented and discussed for the studied field.
Calculation of Average Reservoir Pressure during Primary and Secondary Recovery and Under Variable Boundary Conditions
Authors: Dastan A. , Kamal M. , Collins J. R. , Neubauer E. B. 
Published: October 2012

Abstract
A new method is introduced to calculate the average reservoir pressure around wells from pressure buildup or falloff tests regardless of the shape of the drainage area or the types of boundaries surrounding it. Practicing engineers can apply the proposed method using any of the widely available Well Testing programs. Average reservoir pressure is used in just about all reservoir engineering studies conducted via simulation, material balance, or even decline curve analysis. Existing techniques, such as the Matthews-Brons-Hazebroek (MBH) method (1954), are valid for limited drainage shapes and boundary conditions. In particular, they cannot handle secondary recovery projects (waterflooding, steam injection, etc.), or irregular drainage shapes which are routinely used in the industry. As a result, typically the value of p* is used as a substitute for average reservoir pressure, which may result in significant error.
The new method enables petroleum engineers to calculate the average reservoir pressure accurately for every reservoir type by integrating transient, production, and static data. Our technique calculates a robust approximation of the drainage area based on the production/injection history for each well in the reservoir. A given well may be offset by other injection and production wells and no-flow and/or constant-pressure boundaries, all of which are taken into account for estimation of the drainage area. Our technique also accounts for areal variations in reservoir thickness and depth. The size and shape of the drainage area directly impacts the average pressure characteristics, which can be calculated with the help of relatively simple runs using a reservoir simulator. The results are generalized by creating type curves similar to the MBH type curves for each well in the reservoir.
The new method was applied to several wells in a large oil field offshore Nigeria with the methodology and results presented in this paper. The new technique enables us to calculate the average reservoir pressure accurately for every reservoir type, all drainage area shapes and boundary conditions, a variety of production patterns, and for multiphase flow conditions. It is difficult to overestimate the value of properly calculated average reservoir pressure. It is one of the main parameters used to history match field data. It affects multiple drilling and production optimization decisions like, infill drilling, mud pressure, and determining flow rates of producers and injectors. With accurate average reservoir pressure, optimization of field management is possible by determining the number and the locations of infill wells, the level of injection and production from different wells, and other reservoir performance related decisions. The new method significantly improves our ability to produce valid values of average reservoir pressure.