bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation of Intermittent Gas-Bubbly Oil Three Phase Flow in Upward Vertical Pipe Using the Two-Fluid Model
Authors: Cazarez-Candia O. , Montoya-Hernández D. J. , Bannwart A. C. 
Published: April 2012

Abstract
In the petroleum industry the heavy oil-gas-water three phase flow is present in both, on-shore and offshore pipelines. The adequate predictions of three-phase flow characteristics, such as flow patterns, pressure drop and holdup, can have significant impact on the proper design and operation of pipelines and on many flow assurance issues. To achieve this, experimental work and a rigorous modeling of three-phase flow must be carried out.
When water, heavy oil and gas flow simultaneously through experimental vertical pipes, in such a way that water is the continuous phase, the Intermittent gas-Bubbly oil (Ig-Bo) flow pattern may appear. In this work a one-dimensional, thermal, transient, two-fluid, mathematical model for Ig-Bo flow is presented. The model was developed under the hypothesis that the Ig-Bo flow pattern can be approached by two different flow patterns, each one in neighboring regions: heavy oil-water bubbly flow in an annular region and heavy oil-gas-water bubbly flow in a slug region. The model consists of mass, momentum and energy conservation equations for every phase whose numerical solution is based on the finite difference technique in implicit scheme. The model is able to predict pressure, temperature, volumetric fraction and velocity profiles for each phase. The ratio between the liquid-slug length and the slug-unit length (Λ2), commonly used in two-phase flow, was modified to take into account the presence of heavy oil. It was observed that (Λ2) is larger than the two-phase flow and the correlation allow having the best predictions. The predictions are in agreement with experimental data reported in literature.
Modeling Multiple-Porosity Transport in Gas-Bearing Shale Formations
Authors: Hudson John , Civan Faruk , Michel-Villazon Guillermo , Devegowda Deepak , Sigal Richard 
Published: April 2012

Abstract
Gas-bearing shales are characterized by pore systems that are present in the organic (kerogen) matrix, inorganic matrix, natural fractures, and induced fractures. Each pore system has different physical properties. The organic matrix essentially has gas-wet nanopores with adsorptive properties. The inorganic matrix is an ultra-low permeability matrix that is most likely water-wet but could have more complex wettability. Two alternative but complementary approaches, namely a lumped tank model and a continuum model, for describing gas transport in shale are developed and their capabilities are demonstrated by various applications. Our continuum approach describes gas transport in a manner analogous to the methods employed by commercial simulators. The model is discretized and petrophysical and fluid parameters incorporated into the model that may then be calibrated to obtain a history match. Often, this process leads to non-uniqueness in the match because the number of observations is likely to be smaller than the number of parameters to be resolved. Our lumped tank approach treats the porosity systems within shales as tanks interacting with each other such that relevant physical phenomena, such as adsorption, are described by rate equations. Calibration of this model to production data enables the quantification of grouped parameters and not necessarily the individual storage- and transport-related parameters, thereby reducing the severity of the non-uniqueness of the history matching process. Several case studies conducted exclusively delineate the advantages and disadvantages of both approaches in shale-gas production analysis and simulation. Comparisons between the tank model and the continuum approach for different case studies show good matches within an acceptable measure of tolerance. Reservoir parameters determined from the tank approach are compared with the values used in the continuum approach. The new models are shown to accommodate the inherent complexities of transport processes occurring in shale-gas reservoirs.
Experimental Study of Gel Particles Transport Through Porous Media
Authors: Al-Ibadi A.. , Civan F.. 
Published: April 2012

Abstract
Conditions leading to plugging in weak or highly permeable formations and the resulting permeability impairment occurring during flow of suspensions of deformable gel particles are investigated by core flow tests. Effect of concentration, flow rate, and particle diameter of gel particle suspensions on the relevant pore plugging processes is studied. Effective impairment and trapping mechanisms are identified under various conditions by means of the diagnostic equations. Appropriate dimensionless groups are used to develop empirical correlations of experimental data. This reveals valuable information about the functional trends of porous media plugging by gel particle suspensions which is essential for successful mitigation of formation plugging in the field.
Closure of Natural Fractures Caused by Increased Effective Stress, A Case Study: Reservoir Robore III, Bulo Bulo Field, Bolivia
Authors: Vega Navarro O. G. 
Published: April 2012

Abstract
The gas condensate reservoir Robore III, in the Bulo Bulo field, is comprised by a set of naturally fractured, interbedded shales and sandstones. Recently, this reservoir observed a notorious reduction of its gas reserves and production rates. This reduction in reserves was found to be caused by the geomechanical effect of collapse/closure of its natural fractures. The effect was generated by the sudden increase of effective stress upon the formation. This publication documents the study and investigation of such phenomenon based on core analysis studies, pressure measurements and production data.
Sustained gas production and pressure decline lead to closure of natural fractures as both increase the effective stress and confinement pressure. Consider the fracture network lacks the sufficient natural support agent to counteract increasing pressure, it eventually collapses altering the reservoir quality in the near wellbore region and turning it into a simple matrix permeability reservoir with very low magnitudes of measured permeability (0.001 – 0.01 md). As a consequence, production is severely diminished or even lost.
The present study is the first of its kind in Bolivia as it documents the complete production shut down of a naturally fractured reservoir caused by this phenomenon. A large amount of reserves are stored in gas reservoirs with similar conditions to those observed at the Robore III reservoir, not only in Bolivia but also in the Latin-America region. This peculiarity gives a special significance to this matter. The effect has to be considered in this type of reservoirs when performing reserves estimations, investment decisions or gas production forecasts for contractual matters.
The present study is strongly based on production data from wells BBL-11 and BBL-9D, wellhead and bottomhole pressure information from all completed wells at the reservoir of study and a detailed core analysis report for samples taken form well BBL-11, at depths corresponding to the Robore III reservoir.
After two years of building up pressure, well BBL-11 was opened and its wellhead pressure measured. Pressure was found higher than normal pressure gradient and it was concluded that gas moved into the depleted zone, building pressure up as a result. This well is showing again a steep wellhead pressure and bottomhole pressure decline, as fractures are closing again. Recently drilled well BBL-10 is also showing a steep decline on wellhead pressure. This well is still productive due to reservoir pressure was found to be higher than the normal gradient in this zone and because the fracture network are not yet closing.
Streamlines Simulation of Polymer Slugs Injection in Petroleum Reservoirs
Authors: Vicente B. J. , Priimenko V. I. , Pires A. P. 
Published: April 2012

Abstract
The injection of polymer solutions is an effective method of Enhanced Oil Recovery. However, the continuous injection may be very expensive, and the injection of slugs is an alternative to improve the recovery factor. In this paper, streamlines simulation is used to model the 2D 2-phase oil displacement by polymer slugs, considering adsorption effects.
Streamline simulation can be much faster than conventional finite difference models and its results may be used for slug polymer injection optimization in heterogeneous reservoirs. It decouples the 2D problem into multiple 1D problems along streamlines. The mass transport equations in the streamlines are solved analytically. The continuous polymer injection is a Riemann problem and its solution is self-similar, but in the case of slug injection, there are interactions between waves of different families. We analyze the results for several adsorption isotherms, like Henry and Langmuir.
Analytical solutions are free from numerical diffusion, and allow the choice of greater time steps. The simulations were run in 2D incompressible models without gravity effects. Results obtained were compared with finite difference simulation. The analytical solutions along streamlines allowed the exact modeling of shock and rarefaction waves as well as the interaction between waves of same and different families. Sensitivity analysis was performed regarding the technique adopted for the cell concentration and saturation determination between time steps.
Importance of Distributed Temperature Sensor (DTS) Data for SAGD Reservoir Characterization and History Matching within Ensemble Kalman Filter (EnKF) Framework
Authors: Panwar A. , Trivedi J. J. , Nejadi Siavash 
Published: April 2012

Abstract
Distributed Temperature Sensing (DTS), an optical fiber downhole monitoring technique, provides a continuous and permanent well temperature profile. In SAGD reservoirs, the DTS plays an important role to provide depth- and- time continuous temperature measurement for steam management and production optimization. These temperature observations provide useful information for reservoir characterization and shale detection in SAGD reservoirs. However, use of these massive data for automated SAGD reservoir characterization has not been investigated. The Ensemble Kalman Filter (EnKF), a parameter estimation approach using these real-time temperature observations, provides a highly attractive algorithm for automatic history matching and quantitative reservoir characterization.
Due to its complex geological nature, the shale barrier exhibits as a different facies in Sandstone reservoirs. In such reservoirs, due to non-Gaussian distributions, the traditional EnKF underestimate the uncertainty and fails to obtain a good production data match. We implemented discrete cosine transform (DCT) to parameterize the facies labels with EnKF. Furthermore, to capture geologically meaningful and realistic facies distribution in conjunction with matching observed data, we included fiber-optic sensor temperature data.
Several case studies with different facies distribution and well configurations were conducted. In order to investigate the effect of temperature observations on SAGD reservoir characterization, the number of DTS observations and their locations were varied for each study. The qualities of the history-matched models were assessed by comparing the facies maps, facies distribution, and the Root Mean Square Error (RMSE) of the predicted data mismatch.
Use of temperature data in conjunction with production data demonstrated significant improvement in facies detection and reduced uncertainty for SAGD reservoirs. The RMSE of the predicted data is also improved. The results indicate that the assimilation of DTS data from nearby steam chamber location has a significant potential in significant reduction of uncertainty in steam chamber propagation and production forecast.
Can Injection of Low Temperature Air-Solvent LTASI Be a Solution for Heavy Oil Recovery in Deep Naturally Fractured Reservoirs?
Authors: Mayorquin-Ruiz Jose Ramon , Babadagli Tayfun 
Published: April 2012

Abstract
Heterogeneity and depth rule out steam injection and in-situ combustion processes for heavy-oil recovery in deep naturally fractured reservoirs (NFR). Once it is controlled by a proper injection scheme and the consumption of air injected through efficient diffusion into the matrix, low temperature air injection (LTAI) can be an alternative technique for heavy-oil recovery from deep NFRs.
Limited studies on light oils showed that this process was strongly dependent on an oxygen diffusion coefficient and matrix permeability, both of which are typically low. A new approach, i.e., the addition of hydrocarbon solvent gases into air is expected to improve the diffusivity of the gas mixture and to accelerate the oxidation reaction to breakdown asphaltenic molecules effectively. This improves the gravity drainage recovery from the matrix. To study this new idea called low temperature air-solvent injection (LTASI), laboratory tests were performed by immersing heavy-oil saturated cores into air¬ solvent filled reactors to determine the critical parameters on recovery, diffusion coefficient, oxidation kinetics, viscosity reduction, and gravity drainage rate.
It is imperative that enough time is given for the diffusion process before injected air filling to fracture network breakthrough. This implies that huff and puff injection is an option as opposed to the continuous injection of air. A high recovery factor was obtained by soaking a single matrix in an air-solvent chamber at static conditions rather than with air only. The period of pressure stabilization was faster for the air-solvent mixture atmosphere than in 100% solvent. The asphaltene content was lowered more in the air-solvent chamber than in a 100% air case.
The Impact of the Injection Water Chemistry on Oil Recovery from Carbonate Reservoirs
Authors: Yousef Ali A. , Al-Saleh Salah , Al-Jawfi Mohammed 
Published: April 2012

Abstract
Improved/enhanced oil recovery by tuning the ionic composition of the injection water is currently deemed as new emerging recovery method. In the recent years, extensive research on oil/brine/rock systems has shown that injection low salinity brines in sandstone reservoirs has a significant impact on the amount of oil recovered. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect.
Based on the research work in the last years, we demonstrated in a previous reports (137634; SPEREE Journal, vol. 14(5), pp. 578-593, SPE 143550, SPE 141082) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Also, research confirmed that the main cause for the substantial increase in oil recovery is wettability alteration of carbonate rock surface.
This paper highlights extensive and a broad range of laboratory studies including wettability, surface chemistry, and zeta potential studies to define the role of water ions in the induced wettability alteration, which is crucial in determining the optimum composition of injection water for future field applications.
The rock surface chemistry studies identified the potential mechanisms for wettability alteration triggered by injecting chemistry-optimized field injection water. The contact angle results confirmed that a sufficient reduction in the ionic strength of field injection water is required to trigger the effect of wettability alteration. Zeta potential measurements successfully addressed the impact of multivalent ions on rock surface charges. All evidence gathered during this research work indicates that interplay of water ions is important factor in this new recovery method.
Thermal Development of Thick Heavy Oil Fields: Phase II Development Options, Challenges and Solutions
Authors: Al-Hinai S. M. , Van Wunnik J. N. , Thum M. , Brissenden S. J. , Mukmin M. , Nofli S. , Rabaani A. , Strauss J. P. , Al-Breiki M. 
Published: April 2012

Abstract
A number of thermal developments are currently in execution in Oman. Two of these are located in South Oman and contain an exceptionally thick column (200m+) of heavy oil (200 to 400,000 cp) in Cambrian reservoirs at a depth of 1050 m below surface, underlain by a moderately strong aquifer. One of the fields has been in production for 20 years, the main production mechanisms are pressure depletion and natural ingress of aquifer water, while the other field has only produced a small amount by cyclic steam stimulation (CSS) trials due to the high viscosity of its heavy oil. For the next phase of development a vertical well pattern re-development is planned which will increase the ultimate recovery significantly, through a combination of cold production, CSS and steam flooding.
The thickness of these reservoirs is unusually large for steamflooding and this poses both opportunities and challenges. There are no direct analogues and the industry practices of managing a steamflood in this specific setting is yet to be verified. Phase I deliberately addresses only the upper parts of the reservoirs while significant volumes are still to be matured in a future Phase II development. Following some higher level screening work of recovery mechanisms, the realistic development options for Phase II are innovative application of further steam flooding. Subsurface uncertainties are actively managed by different means; among them are the steam injection trials and steam pilot. The full field developments planned to start-up with Phase I in 2012 followed by Phase II in 2017.
The paper will provide an overview of the proposed Phase II thermal development and specifically the innovative way development challenges are addressed. The integrated modeling work that yielded a better design of well completion strategies will be discussed. Additional topics addressed include minimising additional gas requirements through application of co-generation of electricity and steam (COGEN), water management and overall integrated project management.
Challenges and Risk Management Strategy for Enhanced Oil Recovery Projects in Carbonate Reservoirs of a Giant Field in Middle East
Authors: Choudhary Muhammad A. , Wani Mohamad R. , Al-Mahmeed Ali , Al-Rashidi Hussain 
Published: April 2012

Abstract
Late Cretaceous – Early Tertiary carbonate reservoirs of the giant Wafra Field, located in the Kuwait - Saudi Arabia Divided Zone, hold huge resource of heavy oil in 3 reservoirs, namely 1st Eocene, 2nd Eocene, and Maastrichtian. More than 50 years of primary production from these high porosity, moderate permeability carbonates has recovered less than 5% of this volume and the ultimate recovery is not expected to exceed 10%. Low primary recovery is attributed to oil gravity, viscosity and drive mechanism. Suitable EOR technology is needed to unlock these huge resources. In absence of any commercial analogs, application of EOR technology carries enormous risks in terms of technical viability, reserves recovery and resources commitment. Proper understanding of the reservoir and optimization of EOR technology are essential to mitigate these risks to a manageable level.
This paper will discuss the process used to meet various challenges and mitigate risks of EOR application in 1st and 2nd Eocene reservoirs through exhaustive screening studies, pilot projects and testing innovative technologies. Detailed screening study suggested the suitability of steamflood for 1st Eocene and both waterflood and steamflood for the deeper 2nd Eocene reservoir. Both projects have serious challenges due to reservoir nature, uncertainty in reservoir characterization, non-availability of fresh water, lack of proven technology for processing produced water for steam generation, disposal of excess produced water, fuel for steam generation, and safe environment for workers, public and wild life. These challenges make the EOR projects very high risk ventures. These risks are being managed through extensive G&G and simulation studies, exhaustive screening work and properly designed pilot projects. Five pilot projects are under implementation to resolve the number of uncertainties and manage associated risks in the high reward EOR process for these reservoirs.
This paper will share the strategy, work flow, uncertainty management and risk mitigation plan for these pilot projects and innovative technology being tested to manage challenges in full field application of EOR in carbonate reservoirs. Sharing of processes and innovative technology with industry will lead to success in mitigation of risks in EOR projects in carbonate reservoirs.
Numerical Simulation of Surfactant-Polymer Coreflooding Experiments for Carbonates
Authors: AlSofi Abdulkareem M , Liu Jim S , Han Ming 
Published: April 2012

Abstract
Surfactant/polymer (SP) flooding is of particular interest in recent years due to its synergetic effects of interfacial tension reduction and mobility control with minimal side effects. This work focuses on constructing an SP simulation model using laboratory data and validating it by matching coreflooding results. A series of SP coreflooding experiments were performed in carbonate cores under reservoir conditions. Chemical injection was implemented in tertiary mode with varying slug sizes and concentrations. The coreflooding results show significant oil recovery potential for SP formulations under the conditions investigated. The base SP flood resulted in 23.4% incremental recovery after waterflooding with the polymer and surfactant contributions being about the same. The results also demonstrate the effects of surfactant slug-size and concentration on the recovery performance. Using UTCHEM the input parameters, necessary to predict incremental recoveries, were investigated. A general SP simulation model was initiated, in which: polymer viscosity dependence on concentration and salinity were established in the laboratory; surfactant phase behavior parameters were generated from test-tube results; and oil desaturation was based on additional coreflooding. After matching water and polymer flooding results, the surfactant simulation model was tuned through history matching the performance of a series of SP corefloods. A subsequent sensitivity analysis establishes the confidence level of the input parameters. The sensitivity analysis also highlights the significance of IFT reduction. Finally, we numerically investigated the optimum chemical formulation. Optimization runs were performed under a fixed chemical consumption condition. The results support the optimality of previously selected slug sizes while suggesting the potential benefit of increasing the polymer: surfactant concentration ratio. In summary, this work provides a predictive SP simulation model that can be used to upscale laboratory results to field-scale predictions.