bluuebunny/crossref_metadata_2025_split huggingface dataset:
Foam-Assisted WAG: Experience from the Snorre Field
Authors: Skauge A. , Aarra M. G. , Surguchev L. , Martinsen H. A. , Rasmussen L. 
Published: December 2007

Abstract
The Foam Assisted WAG (FAWAG) has been a large-scale demonstration of foam for gas mobility control. Foam has been applied at the Snorre, North Sea Brent-type sandstone reservoir, for different purposes. First initiated as a gas shut-off production well treatment, thereafter as two large-scale gas mobility control processes.
Combined water and gas injection (WAG) is the main oil recovery method at the Snorre field. Early gas breakthrough in some production wells has limited the oil production. Gas production control is one of the major reservoir management challenges on Snorre. Foam for mobility control has the potential to improve gas sweep in the Snorre WAG process.
Results from the last trial on the Western fault block were very conclusive. Gas breakthrough was delayed, but equally important the Gas-Oil-Ratio (GOR) was considerable lower than gas injection cycles prior to the foam treatment. The paper summarizes all the foam field trails at the Snorre field, with emphasis on interpretation of the last foam application on the Western fault block.
The Snorre FAWAG is the world's largest application of foam in the oil industry. The logistics involved transport of 2000 tons of chemicals from central Europe to the field location. The application of FAWAG has qualified foam as a gas mobility agent for North Sea reservoirs. Large volumes of gas have been stored in the reservoir. The expenses for FAWAG on Western Fault block (WFB) was 1M USD, and additional oil recovery value was ∼ 25-40M USD at current oil prices.
Use of the Method of Characteristics to Study Three-Phase Flow
Authors: González Marta , Araujo Mariela 
Published: December 2007

Abstract
Numerical simulation of multiphase flow is the most acceptable method for the prediction of oil recovery. Recently, the modeling of the three-phase flow has become critical since it may occur in a variety of conditions such as when gas is injected in a reservoir, or when gas or condensate appears as the reservoir pressure drops. Gas injection includes hydrocarbon gas, CO&lt;SUB&gt;2&lt;/SUB&gt;, air, nitrogen or steam injection as well as WAG or gravity drainage. For such processes, the modeling of fluid displacement must include hysteresis in the relative permeability curves.
In this work, the method of characteristics is used to study the effect of rock geometry and wettability condition on the saturation paths for a three-phase system. With this method the partial differential equations used to describe fluid transport are converted into a set of ordinary differential equations which are integrated simultaneously. The method gives information about the flow behavior (fractional flow curves) and the saturation trajectories represented on a ternary diagram.
Imbibition and drainage processes are modeled using relative permeability curves calculated with a fractal pore model, on samples of strong wettability contrast: water wet, intermediate and oil wet respectively. The effect of the rock geometry and wettability condition on the saturation trajectories is analyzed.
Herein, the most relevant contribution of this work is a fast and accurate method to study the gemoetry and wettability effects on three-phase flow properties, such as relative permeability. These properties are relevant for the understanding of oil production and the design and selection of the more appropriate oil recovery strategies.
Laboratory Testing of Polymer Flood Candidates: San Francisco Field
Authors: Saavedra N. F. , Gaviria W. , Davitt J. 
Published: December 2007

Abstract
A technical feasibility study of a polymer-augmented waterflood process in San Francisco Field indicated that this enhanced oil recovery process might be commercially feasible. Since the feasibility study used hypothetical polymer properties, laboratory measurements of specific commercially available polymers were required. The experimental program was divided into three phases. A screening program to reduce the number of candidates. Basic fluid rheological data and quality were developed. For each polymer candidate, four polymer concentrations in three different salinity brines were prepared. Screen Factor tests, Filtration Ratio and viscosity measurements were obtained for each solution. The results were compared to select the best polymers for further testing.Core flooding experiments of the selected candidates. Parameters describing the rock polymer interactions (polymer adsorption and residual resistance factor) were developed. The polymer flow properties (viscosity versus shear rate) developed in the first phase were tuned to match the core flow experiments in a reservoir simulation model.A thermal aging study to verify that the selected polymer does not degrade significantly at reservoir temperature over time. This was a long-term test (six months duration).This paper describes the application of the procedures described in the American Petroleum institute publication RP63, dated June 1, 1990, "Recommended Practices for Evaluation of Polymers Used in Enhanced Oil Recovery Operations", and a case history of laboratory testing of polymer flood candidates.
An Overview of Streamline Tracer Modeling of Miscible/Immiscible WAG Injection IOR
Authors: Ruan F. , Carhart S. , Giordano R. M. , Grinestaff G. H. , Bratvedt F. , Olufsen R. 
Published: December 2007

Abstract
The streamline-based tracer model1 has been successfully deployed to history match and predict miscible and immiscible Water Alternating Gas (WAG) processes at the field scale. The tracer model is a simplified method for the three-phase WAG process, and is computed parallel to the traditional streamline waterflood model. This paper provides an overview to illustrate the relevant concepts and applications of the streamline-based tracer model. A Prudhoe Bay example of the vertical Miscible Injection Stimulation Technique (MIST) is presented to demonstrate and to verify the field use of the tracer model.
Modeling and Simulation of Non-Darcy Flow in Porous Media
Authors: Li Dacun , Engler Thomas W. 
Published: December 2007

Abstract
Consideration of non-Darcy flow effects is essential to adequately model high-velocity flow effects. The relationship between velocity and pressure loss relies on the Forchheimer equation, which includes an empirically derived non-Darcy flow coefficient. The key issue in analyzing the non-Darcy flow is to accurately determine the non-Darcy coefficient. In this work, a semi-theoretical equation is proposed to estimate the non-Darcy coefficient for heterogeneous, porous media. It was determined that two previous theoretical models, parallel-type and serial-type, are upper and lower bounds to the proposed general correlation. The proposed equation can be used to predict the non-Darcy coefficient in porous media where parallel-type and serial-type models are deficient due to heterogeneity and directional permeability.
The semi-theoretical equation was incorporated into a two-dimensional, single-phase gas flow simulator. This simulator was applied to a series of flow experiments where nitrogen was horizontally injected at various flow rates and in several directions into a 3-inch diameter by 3/8-inch thick heterogeneous core wafer. Results from the simulator successfully matched the experimental data, subsequently verifying the proposed correlation. In some directions, parallel-type or serial-type model was as good as the proposed correlation to be used to predict the non-Darcy coefficient; however, in one direction, the proposed correlation was better.
The general equation for the non-Darcy coefficient has been verified by comparing differential pressures from simulations and their counterparts from the wafer non-Darcy flow experiments. The equation will help investigators to reach a better estimation of the non-Darcy effect in porous media. Furthermore, the modeling of the non-Darcy flow developed in this paper can easily be incorporated into a reservoir simulator to account for non-Darcy effect at high velocities.
Microbial Enhanced Oil Recovery: Research Studies in the Arabic Area During the Last Ten Years
Authors: Sayyouh M. H. 
Published: December 2007

Abstract
More than ten strains of bacteria were isolated from Saudi and Egyptian crude oils and formation waters. Experimental investigation was carried out to identify the bacterial isolates, determine the compositions of the appropriate nutrients, conduct surface phenomena measurements. Based on the results obtained, it was found that presence of bacteria affected the solution phase volume, interfacial tension between oil and water, rock wettability, and relative permeability characteristics. These effects depend upon the bacterial type, nutrient type and concentration, salinity, temperature, composition of the crude oil.
A series of microbial displacement laboratory tests were carried out in homogeneous sandpacks and Berea sandstone cores using different types of bacterial solutions of glucose, sucrose and molasses based nutrients. The effects of nutrient type and its concentration, bacterial type, salinity, API, and permeability on oil recovery were investigated. Results show that the greatest oil recovery was obtained from activation of the indigenous bacteria by 1% molasses concentration. Some strains of bacteria were found to produce biogas, biosurfactant and biopolymers which increased oil recovery. The changes in sandpack permeability or API gravity have no effect on oil recovery.
Successful Acid Treatments in Horizontal Openholes Using Dynamic Diversion and Downhole Mixing—An In-Depth Postjob Evaluation
Authors: Surjaatmadja Jim B. , McDaniel B. W. , Cheng Alick , Rispler Keith , Rees Matthew J. , Khallad Abe 
Published: December 2007

AbstractThis paper discusses a relatively new acid-stimulation process that uses dynamic fluid energy to divert flow into a specific fracture point in the well, which can initiate and accurately place a fracture. The acid-stimulation process often uses two independent fluid streams: one in the pipe and one in the annulus. With this process, two different fluids can be mixed downhole with high energy to form a homogenous mixture.Four such treatments in four openhole, horizontal wells were performed in one formation. The first well was acidfractured with coiled tubing to replace many small fractures along the open hole. The second well was acid-fractured with coiled tubing, but downhole mixing concepts were used to provide in-situ generation of CO2 foam. Fewer, yet larger, fractures were placed in this well. The third and fourth wells were treated with acid using rotating and nonrotating jetting tools while mixing the acid with CO2 downhole. Many small, near-wellbore fractures were expected in these wells.Investigating the mechanism that may have contributed to these successes in the field is important. Laboratory tests were performed to analyze the jetting mechanism exposed to rock. The findings of these tests are reported in this paper.
Using Statistics to Evaluate a History Match
Authors: Uldrich David , Matar Saad , Miller Hugh 
Published: December 2007

Abstract
Three methods are proposed for quickly evaluating the history match of a numerical simulation to actual reservoir performance. All of the methods rely on computing a set of deviation values, each of which is defined to be a calculated simulator result minus the corresponding surveillance measurement value.
For any particular type of surveillance data, such as rates, watercuts, or gas-oil ratios, the deviation values can be grouped by well, by area, or combining all measurements in the database. The first two proposed methods rely on simple graphical presentations of each group of deviation values to show how well the simulation results match the surveillance data. Plotting together the results from more than one simulation run allows a quick comparison of the match for each run, which is useful during the history match process.
The third method converts each deviation value to a quantity called Match Factor, which is a relative measure of the confidence that the simulator actually reproduced the particular reservoir performance at the time the surveillance measurement was made. Weighted-average Match Factors can reveal the degree of match by well, by area, and by data type.
These techniques are especially valuable when matching reservoirs with a large volume of surveillance data. They can help focus the history matching process by identifying areas less well matched. They can identify when the history matching process is not significantly improving the match and can stop.
Evaluating Crude Oils by SARA Analysis
Authors: Fan Tianguang , Wang Jianxin , Buckley Jill S. 
Published: December 2007

Abstract
The effectiveness of some improved oil recovery schemes can depend on the composition of the target oil. Crude oils can be described compositionally by a number of methods. SARA analysis divides crude oil components according to their polarizability and polarity using a family of related analytical techniques. Problems arise because several of the analytical techniques in use do not produce identical results, although the users of the data rarely distinguish between them, assuming that SARA fraction values generated by any of the common techniques are essentially interchangeable. We examine this assumption for three SARA analysis methods: gravity-driven chromatographic separation, thin layer chromatography (TLC), and high pressure liquid chromatography (HPLC). Results for a suite of six crude oil samples show that a significant volume of volatile material that contains both saturates and aromatics is lost in the TLC analysis. Application of SARA fraction data to assessment of asphaltene stability is demonstrated.
Oil Deposits in Diatomites: A New Challenge for Subterranean Mechanics
Authors: Barenblatt G. I. , Patzek T. W. , Prostokishin V. M. , Silin D. B. 
Published: December 2007

Abstract
Because of their size and difficulties with oil recovery, the oil-bearing diatomite formations attract now special attention worldwide. For example, the giant diatomaceous oil fields in California, Lost Hills and Belridge, contain some 10 billion barrels of oil in place. Diatomaceous strata have peculiar geological structure: as a result of the cyclic deposition, the diatomite rocks are layered across width scales ranging from tens of meters to sub-millimeter. The diatomite rock is very fragile and its fracture toughness is low: the inter-layer boundaries are weakly connected and ready to part when the fluid pressure changes. When intact, the diatomite has porosity of 50-70% and is almost impermeable (0.1-1 md). Oil production from the diatomites was always difficult and started only 30 years ago after the introduction of hydrofracturing. The scanning electron microscopy images of the diatomite rock reveal a disordered microstructure with little grain interlocking and cementation. Therefore, fluid flow through the diatomite starts only after changes of the rock microstructure. The hydrofractures are not single vertical cracks, but are complex, multiply connected regions of damaged rock.
The current models of fluid-rock systems, e.g., Refs.,1,3,19 cannot capture the dramatic rearrangements of the diatomite microstructure caused by fluid withdrawal and injection, and have little predictive capability. In particular, these models cannot capture the intense rock damage during hydrofracturing, followed by the nonequilibrium countercurrent imbibition with the ensuing rock damage and hysteretic effects. To understand and predict reservoir behavior in the diatomite and limit well failures, a new micromechanical approach has been developed.
Simulating Fractured Reservoirs Using Adaptive Dual Continuum
Authors: Ganzer L. J. 
Published: December 2007

Abstract
This paper presents a new approach for the simulation of fractured or partially fractured reservoirs with a general-purpose reservoir simulator.
In many fractured reservoirs, fractures could be found in limited zones or "sweetspots". Hence, not all parts of the reservoir will typically require dual porosity or dual permeability treatment. The method presented in this paper allows creation of dual porosity or dual permeability cells wherever the attributes of the fracture geological model suggest to do so. The remaining - unfractured - part of the model can be treated like conventional single porosity areas. This approach will be called adaptive dual continuum. As a result, the generated simulation grid block models will resemble the real geological situation more closely than any other modeling approach. This will result in maximum reliability of the simulation model and allow better estimation of recovery for the various recovery processes modeled.
All fracture and matrix-fracture transfer properties are derived from the geological information and fracture intensity. The simulator - that applies an unstructured gridding method - will store them on a cell by cell basis. The paper will discuss the new workflow from generating the geological model by combining the strengths of continuous and discrete models, thereby achieving a high level of data integration until the consistent data export into the reservoir simulator.
The adaptive dual continuum approach was successfully implemented into a commercial reservoir simulator and several examples will prove the capability of this reservoir modeling approach for accurate and economic simulation of fractured or partially fractured reservoirs.
Near-Well Reservoir Monitoring Through Ensemble Kalman Filter
Authors: Geir Nævdal , Mannseth Trond , Vefring Erlend H. 
Published: December 2007

Abstract
In the management of reservoirs it is an important issue to utilize the available data in order to make accurate forecasts. In this paper a novel approach for frequent updating of the near-well reservoir model as new measurements becomes available is presented. The main focus of this approach is to have an updated model usable for forecasting. These forecasts should have initial values that are consistent with recent measurements.
The novel approach is based on utilizing a Kalman filter technique. The idea behind the Kalman filter is to incorporate the information from the measurements into the current estimate of the state of the model, taking into account the uncertainty that belongs both to the state of the model and the measurements. The uncertainty of the model is updated simultaneously with the model itself. A benefit of this approach compared to usual history matching is that the initial values for the forecasts will be in better agreement with the current measurements.
Originally, the Kalman filter had shortcomings for large, non-linear models. During the last decade, however, Kalman filter techniques has been further developed, and applied successfully for such models within oceanographic and hydrodynamic application. This work is based on use of the ensemble Kalman filter. The ensemble Kalman filter is easy to implement, and have some good properties for non-linear problems. Here, we demonstrate the use of this technique within near-well reservoir monitoring, focusing on its performance in forecasting the future production.
Microbiological Production of Surfactant from Agricultural Residuals for IOR Application
Authors: Bala Gregory A. , Bruhn Debby F. , Fox Sandra L. , Noah Karl S. , Thompson David N. 
Published: December 2007

Abstract
Utilization of surfactants for IOR is an accepted technique with high potential. However, technology application is frequently limited by cost. Biosurfactants (surface-active molecules produced by microorganisms) are commonly used in specialty markets such as food and textiles and have potential for IOR application. Currently, biosurfactants are not widely utilized in the petroleum industry due to high production costs associated with use of expensive substrates and inefficient product recovery methods. The economics of biosurfactant production could be significantly impacted through use of media optimization and application of inexpensive carbon substrates such as agricultural process residuals. Utilization of biosurfactants produced from agricultural residuals may 1) result in an economic advantage for surfactant production and technology application, and 2) convert a substantial agricultural waste stream to a value-added product for IOR. A biosurfactant with high potential for use is surfactin, a lipopeptide biosurfactant, produced by Bacillus subtilis. Reported here is the production and potential IOR utilization of surfactin produced by Bacillus subtilis (American Type Culture Collection (ATCC) 21332) from starch-based media. Production of surfactants from microbiological growth media based on simple sugars, chemically pure starch medium, simulated liquid and solid potato-process effluent media, a commercially prepared potato starch in mineral salts, and process effluent from a potato processor is discussed. Additionally, the effect of chemical and physical pretreatments on starchy feedstocks is discussed.
This paper presents an overview of previous work. This effort details the progress of research from initial observation of surfactin production from simple growth media through production of surfactin from process effluents from a local potato processor, and finally, potential reactor design for continuous operation.1,2,3,4
Geological Characterization of Naturally Fractured Reservoirs Using Multiple Point Geostatistics
Authors: Liu Xiaohuan , Srinivasan Sanjay , Wong Dale 
Published: December 2007

Abstract
The spatial distribution of fractures in a reservoir affects the displacement of fluids and the prediction of future performance. Realistic characterization of fractured reservoirs requires quantification and classification of fracture patterns on the basis of the underlying geological characteristics and developing reservoir modeling algorithms that can integrate connectivity based (multiple point) statistics related to fracture patterns. A methodology for summarizing the characteristics of fracture networks based on multiple point connectivity functions is presented. The paper also presents a stochastic simulation methodology for constraining the target reservoir model to the connectivity characteristics derived from analog models and to all other available reservoir specific data in the form of well information and seismic areal proportion maps.
Acidizing in Naturally Fractured Carbonate Reservoirs
Authors: Dong C. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
In this paper, we present a methodology for predicting the propagation of acid along natural fracture networks and the resulting etching of the fracture walls as well as the skin factor of an acidized naturally-fractured well. The natural fracture network is modeled as a system of intersecting fractures that form a main pathway for acid transport and dissolution. The tails of the intersected fractures increase the leakoff from the main pathway and are accounted for in the model. The fracture network acidizing model is supported by comparisons with laboratory experiments and smaller scale simulations that determined the nature of acid channeling at fracture intersections. Model results illustrate the effects of variations in fracture properties on acid propagation. Prats' model is used to calculate the skin factor of an acidized, naturally-fractured well. The model predicts deeper acid penetration (up to 5 meters) under matrix conditions than would be possible with only matrix flow. Acid-etched fractures of this length result in skin factors of -2 to -3, similar to that observed in many carbonate acidizing treatments.