bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Modeling Methods And Characterization Parameters For A Shoreface Reservoir: What Is Important For Fluid Flow Performance?
Authors: Jian F. X. , Larue D. K. , Castellini A. , Toldi J. 
Published: December 2007

Abstract
About fifty reservoir characterizations were built using seven different modeling methods, and by varying a combination of reservoir characterization parameters using Experimental Design. The methods include: 1) simple sequential gaussian simulation (SGS); 2) SGS with stratification; 3) SGS with reservoir quality map trend and no stratification; 4) SGS with reservoir quality map trend and stratification; 5) sequential screening simulation with 3D trend; 6) truncated gaussian simulation with trend and 7) general marked point process. These fifty models were all subjected to fluid flow simulation with an active aquifer and limited peripheral waterflooding.
The results show that oil recovery at 95% water cut ranges from 29% to 34% in these fifty models despite the large apparent visual differences between them. However, there are large differences, some greater than 200%, in water breakthrough time, water cut and cumulative water production. Based on fluid flow performance, these fifty models are classified into three groups. Group 1 includes models constructed using short variogram ranges in Methods 1 to 4, or medium variogram ranges without stratification in Methods 1 and 3. They behaved more homogeneously and produced flow characterized by later water breakthrough and lower watercut. Group 2 are those models constructed using long variogram ranges in Methods 1 to 4, or medium variogram range with stratification in Method 2 and 4. They behaved more heterogeneously and produced early water breakthrough and high overall watercuts. Even though the mean permeability was similar in the oil zone for the two groups of models, the effects of continuity imposed by the variogram and stratification controlled this disparate behavior. Models of Methods 5 to 7 comprise Group 3, which produced the earliest water breakthrough and the highest overall watercuts. We interpret the difference in water breakthrough time and watercut between Group 2 and 3 to be a result of the higher average permeability (by 100-200 mD) in the oil zone of Group 3 models.
Do more complex, geologically realistic models provide the best frameworks for predicting flow performance in sandy shoreface reservoirs with good well control? Some of the simplest models we constructed provided similar flow simulation results as the most complex and soft-data conditioned models. What we do observe, however, is that the more soft conditioning data used and the more complex geologic models tend to give a restricted range in full field flow performance.
Source Parameters of Hydraulic Fracture Induced Microseismicity
Authors: Urbancic T. I. , Maxwell S. C. 
Published: December 2007

Abstract
Microseismic results are presented for hydraulic fracture stimulations monitored in the Cotton Valley, East Texas. In particular, we examine whether additional information on the microseismic source such as the apparent stress release values can be used to effectively identify differences in the generation process of individual or clusters of microseismic events and the development of the overall hydraulic fracture in both space and time. Trends in apparent stress have been used to establish different modes of failure, with increased apparent stress values at the leading edge of the hydraulic fracture and lower apparent stress values behind the leading edge. We suggest that the failures are along a pre-existing network of fractures and include significant non-shear components of failure for events occurring behind the hydraulic fracture front. At the extremities of the hydraulic fracture as the stimulation proceeds we suggest that the redistribution of stresses as a result of the injection increase the average shear driving stress resulting in shear dominated failures. Overall, the hydraulic fracture can be characterized by regions of shear and nonshear type failures, further suggesting that the relative permeability of the fracture network can possibly be identified.
Integrating Pressure-Transient and Seismic Data to Determine the Characteristics of Single-And Double-Porosity Reservoirs
Authors: Cardona R. , Ozkan E. , Batzle M. 
Published: December 2007

Abstract
This paper presents an approach that integrates pressure transient and multi-component seismic data to determine the characteristics of single- and double-porosity reservoirs. It is shown that a functional dependence exists between the well-test-determined storage capacity ratio and the seismic estimate of the normal fracture compliance. This functional dependence provides a means to obtain an estimate of the normal fracture compliance from well-test data or an estimate of the storage capacity ratio from seismic data. Obtaining estimates of these parameters by independent means helps reduce the nonuniqueness problem encountered in the interpretation of well-test or seismic data by reducing the number of parameters to be determined. In addition, it is shown that assuming a fracture model, the fracture density may be predicted from the storage capacity ratio. The application of the approach developed in this work is demonstrated by the analysis of the pressure buildup data from the Weyburn Field.
Design of a Crude Oil Dehydration Unit
Authors: Noïk C. , Trapy J. , Mouret A. , Laborie G. 
Published: December 2007

Abstract
The purpose of the study is to develop a compact electrocoalescer. To improve oil/water separation, definition of optimized conditions for coalescence of water droplets under an electrical field in combination with optimal hydrodynamic performances was performed. Numerical simulations carried out with the CFD code fluent permit to design a new dehydrator integrating the three functions of electrocoalescence, centrifugation and phase separation.
A first part consists of two concentric cylindrical vessels used as electrodes with a tangential flow introduction. Then the speed of water droplets is accelerated in a second step by centrifugal effect. Finally, the water flow is separated from the oil phase in a third part. A laboratory prototype was built and tested in various conditions of flow rate and with different types of crude oil/water emulsions. Encouraging results led to define and patent a new concept of compact centrifugal electrocoalescer.
Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems
Authors: Tengesdal J.Ø. , Sarica Cem , Thompson Leslie 
Published: December 2007

Abstract
Recently, exploitation of offshore petroleum reservoirs has moved to ever increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deep-water risers that conduct production from multiple wellheads on the sea floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. Considering the length of the deep-water risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences such as premature field abandonment, loss of recoverable reserves and earlier-than-planned deployment of boosting devices.
In this study, a novel idea to lessen or eliminate severe slugging in pipeline-riser systems has been thoroughly investigated. This idea was first proposed by Barbuto3, and later developed independently by Sarica and Tengesdal9. The principle of the technique is to transfer the pipeline gas to the riser at a point above the riser-base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating the severe slugging by maintaining the steady-state two-phase flow in the riser.
An experimental study has been conducted using a 7.62 cm. inner diameter riser (14.63 m high) and pipeline (19.81 m long) system. A broad range of data was collected from the facility both in the severe slugging and stable regions. It was found that currently available severe slugging models do not predict the severe slugging region accurately for larger diameter pipes. Data acquired with the external gas bypass have proven the proposed elimination technique.
Surface Gravity Monitoring of the Gas Cap Water Injection Project - Prudhoe Bay, Alaska
Authors: Brady Jerry L. , Ferguson John F. , Seibert John E. , Chen Tianyou , Hare Jennifer L. , Aiken Carlos V. L. , Brown Fred J. , Klopping John M. 
Published: December 2007

Abstract
The world's first 4-D surface gravity surveillance of a waterflood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the approved Gas Cap Waterflood Project (GCWI) at Prudhoe Bay. A major factor in the approval of the waterflood was to show that water movement could be economically monitored with a very limited number of wells. Conventional monitoring techniques would have been cost prohibitive due to the requirement for drilling numerous new surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be detected using high-resolution surface gravity measurements. Field tests at Prudhoe Bay have demonstrated that sufficiently accurate gravity data can be obtained.
This paper will discuss both inverse modeling of time differenced gravity maps and four test surveys that have been completed to perfect the gravity measurement technique. Forward and inverse gravity modeling was carried out on a suite of reservoir simulations of the GCWI. Differences in the gravity field with time reflect changes in the reservoir densities, which in turn reflect pore fluid content. A constrained least squares method was used to invert synthetic gravity data for the subsurface density distribution. The modeling procedure has been formulated to allow testing for sensitivity to gravity sampling patterns, noise and various constraints on model parameters such as density, total mass, and moment of inertia.
These simulation results have shown that greater than 95% of the injected water can be accounted for in the inverse model. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average flood front can be reliably detected within 2000 - 3000 ft. for the Prudhoe Bay reservoir that is buried at 8200 ft to 8800 ft tvd. Time differenced surface gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (-40 F) accurately enough to monitor the waterflood (gravity = ± 10 ìGals and GPS = ± 1 cm elevation, a íGal is about one billionth of the Earth's normal gravity).
Waterflood and Production-Induced Stress Changes Dramatically Affect Hydraulic Fracture Behavior in Lost Hills Infill Wells
Authors: Minner W. A. , Wright C. A. , Stanley G. R. , de Pater C. J. , Gorham T. L. , Eckerfield L. D. , Hejl K. A. 
Published: December 2007

Abstract
Water injection and reservoir fluid production result in poroelastic stress changes that can dramatically alter the created fracture geometry on infill wells. This basic conclusion is not new. It has been documented in many different environments, and is supported by theoretical modeling. However, this paper presents for the first time a large data-set of 76 fracture treatments in a concentrated area that not only shows stress reorientation, but also shows how fracture reorientation depends critically on the pattern of injectors and producers and their interaction. This knowledge can be used to improve recovery in water injection projects that depend on closely spaced fractured wells.
Data is presented from 76 fracture stages in 16 infill wells completed within a one-year period in Chevron's Lost Hills diatomite waterflood. Surface tiltmeter fracture mapping determined the fracture orientation (azimuth and dip) of the induced fractures, consisting of a vertical fracture component and a secondary sub-horizontal fracture component. This dataset clearly shows that the interaction between injectors (located in a line along preferred fracture azimuth) and producers results in a large-scale stress perturbation, producing a "room-and-pillar" stress structure. Both the fracture azimuth and the degree of secondary sub-horizontal fracturing are controlled by the location of infill wells with respect to nearby injector wells. Infill wells "inline" with injector wells yield fractures that grow close to the initial preferred fracture orientation. In contrast, infill wells that are "offset" from the line of injector wells yield highly variable fracture azimuths (often rotating towards injector wells) and greatly increased secondary sub-horizontal fracturing – both of which raise the risk of "short-circuiting" waterflood sweep. The data is presented and phenomenologically explained. A geomechanical model explains the observed stress changes, allowing predictive modeling of various infill-drilling scenarios in waterfloods to optimize recovery.
For a number of project treatments, downhole tiltmeter fracture mapping was also used to evaluate fracture dimensions, and fracture pressure analysis was performed to link tilt observations with treatment pressure behavior. Poroelastic effects have resulted in increased stress magnitudes in some layers and decreased stress in others, impacting the created fracture dimensions (height, length, and width). A summary of the mapped fracture dimensions and pressure analysis findings is presented together with a brief discussion of the poroelastic impacts on fracture geometry.
Logistic Approach in Using an Array of Reservoir Simulation and Probabilistic Models in Developing a Giant Oil Reservoir with Super-Permeability and Natural Fractures
Authors: Pham T. R. , Al-Otaibi U. F. , Al-Ali Z. A. , Lawrence P. , Van Lingen P. 
Published: December 2007

Abstract
The development of a large oil increment with super-permeability (super-K) layers, and natural fractures such as Haradh Arab-D poses many challenges, including the optimization of the number of start-up oil producers and injectors, and the selection of depletion mechanism which is preferably peripheral injection in this case. The type of well (vertical or horizontal), and completion intervals have to be investigated. In the case of horizontal wells, direction of the horizontal trajectory is always a difficult issue to decide as well as the optimized length of the horizontal section.
Due to time constraints and the sheer size of the field areal extent (tens of kilometers) and the complex geology of the reservoir, it is not practical to construct a single full-field model which is expected to serve as an all-purpose simulation model that includes all of the reservoir attributes encompassing super-K layers, faults and fractures. This paper will discuss how to use an array of different reservoir simulation models to achieve the objectives within a time-limit dictated by the business plan requirements. Issues such as the number of start-up wells, the production plateau, type of wells, choice of completion intervals, optimized horizontal length, direction of horizontal trajectory can not be answered by one single model. However, each issue can be addressed by a specific model constructed for a single purpose. The development of an oil increment in Haradh is used to illustrate this concept.
Wax Deposition in North Sea Gas Condensate and Oil Systems: Comparison Between Operational Experience and Model Prediction
Authors: Labes-Carrier Catherine , Rønningsen Hans Petter , Kolnes Johnny , Leporcher Emile 
Published: December 2007

Abstract
Control of paraffin deposition is addressed in early phase of new field developments, as part of the fluid-related effects on the flow performance of the multiphase transportation system. Paraffins are precipitated by a decrease of the fluid temperature. During the design phase, a combination of experiments and modeling is used to predict potential wax related problems and determine possible solutions for wax control. High reliability is required from wax deposition models in order to avoid over protective operational guidelines, over design of the transportation system and thereby reduce cost in terms of insulation, pigging and chemical injection.
The main objective of this study is to compare wax deposition predicted by a simulation model to operational data for two different North Sea fields. The first case contemplates a 10-inch, approximately 21 km long multiphase and subsea production pipeline from the High Pressure gas condensate field A to the central gas-processing complex. The production has now come to an end. The second case is a single phase, stabilized oil being transported through a 16 inch, approximately 43 km production pipeline from a processing platform at field B to field C for storage and offloading.
OLGA 2000 with wax module has been used for the dynamic wax deposition simulations. The physical and thermodynamic fluid properties used in the simulations are also presented and discussed. Various model parameters and their influence on modeling results are evaluated.
Field experience after many years of production is available from the gas condensate field A. Although wax deposition was predicted in the gas condensate line, no significant deposit has ever been observed. Wax control for the field B pipeline is currently based on regular pigging every few days combined with continuous injection of wax inhibitor.
There has not been sufficient field data available for a very detailed comparison with modeling results. Anyway, operational experience from two very different fields gives some important insight into the strengths and weaknesses of current modeling tools and practice. A main conclusion of this paper is that wax deposition under field conditions seems to be less severe than predicted by the model for the multiphase gas condensate line, while it seems to be reasonable agreement between modeling and field experience for the single-phase oil case.
Phase Behavior Modeling of Hydrocarbon-Methanol-Water Mixtures by Peng-Robinson and SAFT Equations of State
Authors: Ayyalasomayajula Padmakar , Sharma Ravi , Walker Jacob G. , Sharma Mukul M. , Pope Gary A. 
Published: December 2007

Abstract
The phase behavior of mixtures of hydrocarbons, methanol and water is important in gas-condensate reservoirs as well as in gas hydrates. Gas-condensate wells frequently show reduced productivity when operated below the dew point due to the build up of condensate near the well. A combination of high water and condensate saturation results in a significant reduction in the gas relative permeability. Recently, methanol has been used to remove liquid blocking around such wells and restore well productivity. The phase behavior of such fluid mixtures is difficult to model using currently available equations of state.
In this study, phase behavior data were measured both to help interpret coreflood experiments and for testing of equation-of-state models used in compositional simulation studies of methanol well treatments. The Peng-Robinson equation-of-state and the SAFT equation-of-state were used to model this new phase behavior data. The Peng-Robinson equation-of-state does better than the SAFT equation-of-state for hydrocarbon mixtures. The binary interaction coefficients had to be adjusted in both models to match the experimental data when methanol and water are in the mixture. The SAFT EOS required less tuning to match data from hydrocarbon-methanol mixtures. SAFT EOS, as expected, agrees with the data better than the Peng-Robinson EOS when water is in the mixture.
A New Degree Program in Oil and Gas Engineering
Authors: Ronalds Beverley F. 
Published: December 2007

Abstract
The oil and gas industry is experiencing an ageing workforce and skills shortages, while petroleum engineering schools are struggling and many industry recruits are coming from other degree disciplines. This paper describes how these challenges are being addressed in a Western Australian (WA) context. The overall aim of the oil & gas engineering program at The University of Western Australia (UWA) is to give students an orientation to the extraction, processing and infrastructure requirements of the oil and gas industry. This is achieved by offering maximum flexibility in course offerings (entry level, duration and subject matter) and through maximum utilization of existing teaching resources. Strong industry interaction is another key feature of the program.
Analysis of Generated and Reflected Pressure Waves during Fracturing Reveals Fracture Behavior
Authors: Surjaatmadja Jim B. , Stephenson Stan , Bhaumik Champak , Thompson Stewart , Cheng Alick 
Published: December 2007

Abstract
Fracture behavior is an important aspect in fracturing technology. Many techniques are available for prestimulation simulations and post-stimulation analysis of fracture behavior. However, very few techniques address fracture behavior during the stimulation process itself. Various fracture behaviors, such as fracture extension, ballooning, and tip screenout are often not known to the operator until after it is too late or even after the job is completed. Therefore, it is important to create and evaluate different real-time analysis techniques that can be used to capture the critical information available from data gathered during jobs.
During the stimulation process, many types of information are available to the engineer. Pressure, flow, and temperature are basic information evaluated by many in the past. However, surface-pressure measurements are heavily influenced by friction, densities, proppant concentrations, and flow fluctuations, which makes conventional analyses difficult, if not impossible. In spite of this, analysis of dynamic pressure fluctuations has not been actively pursued. Certain changes in the downhole configuration, such as fracture extension, may send different pressure frequency spectra and wave intensities to the surface. The signature of these pressure waves is believed to carry such information to the surface. It is also believed that signal degradation due to friction may not influence the outcome of this type of analysis.
Capturing and evaluating generated and reflected pressure waves during fracturing may be a new approach to monitor what happens downhole during fracturing. This paper discusses different real-time analysis approaches, such as frequency analysis and wavelet technologies, and evaluates their results and compares them to real job data. These analysis results and the successful stimulation results are presented in this paper.