bluuebunny/crossref_metadata_2025_split huggingface dataset:
Damage Interpretation of Properly and Improperly Drilled Underbalanced Horizontals in the Fractured Jean Marie Reservoir Using Novel Modeling and Methodology
Authors: Kimery Dave , van der Werken Theo 
Published: December 2007

Abstract
The Jean Marie reservoir in the northeastern part of British Columbia, Canada, is one of the most active horizontally underbalanced drilled reservoirs in the world. The Jean Marie is a depleted, low permeability, fractured carbonate with low initial water saturation making it susceptible to formation damage using conventional drilling fluids.1 Given these reservoir characteristics, horizontal underbalanced drilling is the current method of choice for operators active in the area.
Although underbalanced technology has made tremendous improvements in maintaining and ensuring underbalanced conditions at all times during operations, overbalanced incidents do occur while drilling the horizontal section. These incidents can be much more damaging than drilling with a well designed overbalanced fluid. In some cases, an overbalanced event could permanently impair production from a well by as much as 75%.
With the aid of real time downhole pressure gauges, these overbalanced incidents can be identified but very often go undetected, leading to a false sense of achieving the goal of minimal damage. The unidentified damage can lead to misinterpretation of production results and disappointment with underbalanced drilling.
To exacerbate the problem of identifying damage, traditional pressure transient analysis of wells in the Jean Marie may yield incorrect valuation of the overbalanced incidents by underestimating the skin on the face of the horizontal well. This could be due to the difficulty of performing meaningful transient analysis on a horizontal well in a dual porosity reservoir and a general lack of knowledge of the impact of drilling related damage on fractured or highly heterogeneous reservoirs.
This paper will show how, by combining transient productivity index data collected while drilling with the use of history matching techniques, overbalanced incidents can be easily identified and the impact on well productivity can be quantified.
Managed Pressure Drilling for Subsea Applications; Well Control Challenges in Deep Waters
Authors: Fossil Børre , Sangesland Sigbjørn 
Published: December 2007

Abstract
This paper describes a new drilling riser concept and drilling method that will remove some of the well control challenges presently encountered and provide improved well control procedures, when handling deepwater kicks and deep formation gas flow into a well being drilled. The new system will also allow for longer hole sections to be drilled in deepwater, thus reducing the number of casing strings required in the well and reduce the chances of hydrate plugs forming at seabed.
The main element in the system is based on using a smaller size (14"-12.5" ID) high pressure drilling riser with a split BOP between surface and subsea, a subsea mud pump connected to the high pressure drilling riser, taking returns from a lower level in the riser. The mud level in the riser is dropped down to a level considerably below sea level to create a mud/air interface ("mud cap") that can be continuously adjusted up or down by the mud-lift pumping system. As a consequence, the bottom hole hydrostatic pressure will be controlled. One of the main purposes of this system is to mitigate the inherent problems with a conventional 21" marine drilling riser during well control scenarios in deepwater operations. It will adjust the bottom hole pressure accordingly and compensate for frictional pressures due to circulation.
Field-scale Polymer Flooding: Lessons Learnt and Experiences Gained During Past 40 Years
Authors: Du Y. , Guan L. 
Published: December 2007

Abstract
Early in 1964, Pye and Sandiford established the fact that polymer flooding can result in greater oil recovery than the conventional water flooding. Many additional papers sustaining and extending this information have since appeared in the literature. In the past forty years, many field-scale polymer flooding projects have been put into production and lots of information has been available from which to draw conclusions regarding of lessons learnt and experiences gained on field-scale polymer-flooding. The purpose of this paper is to examine the ranges of some important parameters within which successful polymer flooding has been achieved and to present lessons learnt and best practices on polymer flooding, thus direct to design and further achieve a high-performance polymer-flooding project.
Uncertainty Assessment using Experimental Design: Minagish Oolite Reservoir
Authors: Peake W. T. , Abadah M. , Skander L. 
Published: December 2007

Abstract
A peripheral waterflood is planned in the Minagish Oolite Reservoir, Burgan Field. This is a large carbonate reservoir which has been under limited primary production since 1965. There is considerable uncertainty in the waterflood oil forecast because of the minimal amount of data with which to characterize the reservoir. This study identifies key subsurface uncertainties impacting waterflood performance and quantifies uncertainty with P10/P50/P90 oil forecasts.
Experimental design (ED) techniques were used to establish the minimum number of reservoir simulation runs needed to quantify uncertainty. Both traditional and ED techniques were used to preserve history matches for all simulations. Analysis of variance and multiple linear regressions were used to identify the most significant uncertainties and to create a proxy for the simulator. The proxy was used in Monte Carlo simulation to develop P10/P50/P90 oil forecasts.
Uncertainty analyses have not often been conducted on producing reservoirs. In this report a new technique combining ED with history matching has been successfully demonstrated. The technique can be applied to other producing reservoirs. Despite the need to restrict simulator inputs for history matching, it was shown that considerable uncertainty exists in the waterflood oil forecast. The results are valuable for: a) identifying actions to reduce uncertainty and b) input to additional development evaluations.
Characterization of a Vuggy Fractured Media: A Practical Approach
Authors: Pérez-Rosales C. , Luna E. 
Published: December 2007

Abstract
This paper presents the theoretical, experimental, and operational bases of a practical procedure for decomposing total porosity into its basic components, i.e., primary, secondary, fracture, and vug porosities. The procedure makes use of total porosity and formation resistivity factor data obtained through geophysical well logs, and is based on a general formulation which has as particular cases all other formulations commonly used to relate formation resistivity factor and porosity, such as Maxwell, Fricke, Archie and generalized Archie equations. To visualize its potential as a tool for interpreting well logs, an application example is presented.
Dynamic Behavior of Discrete Fracture Network (DFN) Models
Authors: Araujo Hugo , Lacentre Pablo , Zapata Tomás , Del Monte Aldo , Dzelalija Francisco , Gilman James , Meng Hai-Zui , Kazemi Hossein , Ozkan Erdal 
Published: December 2007

Abstract
This work shows that discrete fracture network modeling is very desirable for the characterization of naturally fractured reservoirs but it is only a highly subjective starting point. Thus, calibration against short and long term pressure transient tests is most crucial. This paper shows how the dynamic behavior of a discrete fracture network model of Margarita gas field compared against pressure transient measurements in a sidetrack delineation-well. The performance comparison of a very fine-grid reservoir model, which included the discrete fracture network information, versus a much coarser upscaled grid model is also documented.
In Situ Upgrading Heavy Oil by Aquathermolytic Treatment Under Steam Injection Conditions
Authors: Jiang S. , Liu X. , Liu Y. , Zhong L. 
Published: December 2007

Abstract
Aquathermolytic technology that involves upgrading heavy oil using chemical additives is introduced in this paper. Laboratory experiments were carried out under steam injection conditions to investigate catalysis of some metal species and synergetic effect of catalyst and hydrogen donor on aquathermolysis of Liaohe and Shengli heavy oils. As a result, significant reduction in viscosity and contents of asphaltene and resin was obtained, thus heavy oils were upgraded greatly. Then the mechanism of aquahtermolysis is discussed further. Additionally, the field test in Liaohe Oifield is introduced. The future is suggested in the end.
Reservoirs Simulations of Gel Treatments to Control Water Production, Improve the Sweep Efficiency and the Conformance Factor in Eastern Venezuelan HPHT Fractured Reservoirs
Authors: Herbas Julio , Kumar Sujit , Moreno Raul , Romero Maria F. , Avendaño Horacio 
Published: December 2007

Abstract
A numerical simulation study was undertaken to model the gel treatments in injector and producer wells in Eastern Venezuela Fractured HPHT Reservoirs in exploitation under secondary and tertiary recovery process.
The objective of the simulation study is to develop a numerical simulation model based on field and laboratory data to model the gel treatments to block induced fractures and high permeable channels in water injection and oil producer wells, and to improve the conformance and the recovery factors.
Field data representation of a HPHT Fractured Venezuelan reservoir with preferential water movement and induced fractures was used to build a conformance field prototype model.
The gel used in the simulation study is a polymer system composed by polyacrylamide with phenol and formaldehyde crosslinkers suitable to stand HPHT reservoir conditions. Available laboratory work and field data to characterise the performance of polymer gels in fractured wells were included in the model and were history matched to predict alternate gel treatment scenarios.
The developed simulation model provides a tool to predict the production performance of gel treatment in Eastern Venezuela Fractured HPHT Reservoirs under different treatment scenarios; useful to assist in the determination of: optimum treatment intervals, optimum procedures; and to develop data for economic evaluations, improving the design of gel treatment and reducing associated uncertainties.
Modeling of Gravity-Drainage in Naturally Fractured Reservoirs Using Flow in Angular Capillary Tubes
Authors: Xu Q. , Gupta A. 
Published: December 2007

Abstract
This paper presents an investigation of gravity-driven flow in naturally fractured reservoirs via multiphase flow in angular capillary tubes. The study includes theoretical and numerical analyses, and is supported by laboratory measurements.
Gravity is important in many oil recovery processes, either acting as the driving force in processes using horizontal wells or altering displacement patterns during waterflooding, chemical flooding, CO2 flooding, and other EOR processes.
Gravity drainage driven oil production in naturally fractured and other complex reservoirs falls into two regimes: the bulk flow and the film/corner flow. After the bulk flow at constant production rate and a short period of transition, the corner/film flow dominates the production. The flow in the corners and films in fractures and pore-channels is the focus of this study. Modeling the flow channels as angular capillaries of variable polygon shapes provides a valid physical basis for corner flow.
The fluid distribution above the gas/oil contact is influenced by in-situ capillary force but more by the fluid dynamics. Numerical simulation of the film/corner flow was conducted for various cross sectional shapes using finite element analysis (FEA). Experiments were conducted using space between packing of glass rods as flow channels that capture the essential features of flow channels in rocks and natural fractures. Comparison between the simulation predictions and experimental observations allowed validation of the modeling process.
The results of this study provide basis for more detailed network models, which describe rock-fluid systems at microscopic level with deterministic solutions. The modeling procedure presented in this study and the results are useful for modeling the performance of gravity dominated improved oil recovery processes.
Improving the Recovery Factor of Heavy Crude Reservoirs by Co-injecting CO2 and Other Conventional Gaseous Injecting Materials at Immiscibility Condition with Foam
Authors: Panahi Hamed 
Published: December 2007

Abstract
Gas injection process as both a pressure maintenance method & an IOR method has a long background in the upstream. Adding foam is a proven method for decreasing gas mobility in both homogeneous and heterogeneous reservoirs. Foamed gas, though is a promising agent for achieving mobility control in porous media. Its profound impact on the efficiency of different gas injection applications fascinated the industry on considering using it to supply the future needs of the world to hydrocarbons.
The idea here is to inject CO2 which is immiscible at the start of injection along with a kind of foamer solution. The role of foam is to increase the contact area of the reservoir by reducing the gas mobility leading to higher volumetric sweep efficiency and mitigating the so-called effect of gravity override. The process is completed by injecting gas to the amount that it becomes miscible. (Reservoir pressure goes beyond MMP). No production is expected after the initial injection to the time we are certain that the whole system is in thermodynamic equilibrium. The in depth theoretical description is included.
The simulation of the process is performed using a coded isothermal compositional simulator together with commercial reservoir simulation soft-wares, though simulation models and simulation tools that accurately gauge the effects of foam on gas mobility in porous media are not readily available.
The simulation results are compared with the experimental results. Feasibility study is performed and the setbacks of the process are analyzed. Some remedies are offered to improve the process.
Case Histories - Combining Crossed Dipole Sonic Anisotropy and Oriented Perforating To Optimize Hydraulic Fracturing In the Burgos Basin - Reynosa Mexico
Authors: Patino Antonio Hernandez , Garcia Eduardo Rodriguez , Torne Juan Pablo , Lazo Jorge , Kessler Calvin 
Published: December 2007

Abstract

Proposal
Based on local experience, a well-accepted work flow or set of best practices has been developed for optimizing stimulation treatments in the Burgos Basin. Recently, these best practices have been enhanced by combining stress field orientation and gyroscopically oriented wireline perforating. Orienting perforations in the direction of maximum horizontal stress has greatly reduced near wellbore tortuosity and friction in hydraulic fracturing treatments. The result has been improved proppant placement resulting in higher proppant conductivity and increased production.
The best practices for optimization of the stimulation design and economic modeling include many steps.1,2,3,4,5,6,7,8,9,10 The candidate selection process evaluates the net-to-gross sand thickness ratio, reservoir pressure, and permeability for each zone. The net-to-gross ratio provides information on productive and non-productive fracture height, which is needed for inflow analysis. The reservoir fluid, pressure, and permeability of the formation are vital for determining the fluid leakoff/fracturing fluid rheology requirements and required fracture conductivity. Geological and geophysical data are reviewed to identify potential reservoir boundaries such as faults or pinch-outs that could impede hydraulic fracture propagation. The vertical stress profile between the zone to be treated and the underlying and overlaying formations is used in 3D fracture simulators to evaluate the fracture height (and any possible unwanted out-of-zone fracture height) versus fracture half-length and proppant concentration.
To implement the oriented perforating enhancement to the best practices crossed dipole sonic anisotropy analysis is used to determine the far-field stress orientation and magnitude combined with the six electrode dipmeter for orientation and ovality visualization. Borehole breakout analysis and anelastic strain recovery of whole cores can provide near-field stress orientation data. These factors are then used to determine optimum perforation direction. In this paper, several case histories will be presented comparing the results of stimulation treatments using the normal practices and traditional perforating methods versus stimulation treatments using the same practices but incorporating oriented perforating.
Fracturing Microseismic Response in Turbidite Reservoirs in Tajin Field
Authors: Berumen Sergio , Kaiser Penelope , Gachuz Heron , de Swaan Abraham , Rodriguez Juan M. 
Published: December 2007

Abstract
Selection of optimum well locations in heterogeneous turbidite reservoirs such as those found in Chicontepec basin, depends strongly on the description of heterogeneities--facies distribution and flow quality properties--as well as on the evaluation of the extent and orientation of propped fractures. Fracture growth propagation and orientation play an important role in visualizing and optimizing the drainage pattern of such complex reservoirs.
To better understand the fracturing response of these formations and support the design of development strategies, several measurements of microseismic response under hydraulic fracturing were carried out in wells in the Tajin field. By deploying sensor on-tubing tools of treatment wells, microseismic data were recorded following the injection operation, yielded fracture extent and orientation and stress anisotropy. The computed hypocentre locations are distributed in a non symmetric cloud of seismicity with a global trend extending no farther than 195m away from the wellbore in the N20-30°E direction. Moreover, the acoustic emissions presented a remarkably consistent direction.
Interpretation of location of shear-slip and acoustic emissions events is consistent with results provided by dipolar sonic image logging tools run on the same wells. Better understanding of reservoirs` response to stimulation leads the operator to review its fracturing practices for cost-effective reservoir stimulation. Numerical reservoir simulation grids for reservoirs in the zone were oriented according to the observed fracture trend.
Reservoir Simulation of Non Selective Placement of a Polymer Gel Treatment to Improve Water Injection Profiles and Sweep Efficiency in the Lagomar Field Western Venezuela
Authors: Herbas Julio , Moreno Raul , Marin T. Amaury , Romero Maria F. , Coombe Dennis 
Published: December 2007

Abstract
A reservoir numerical simulation study was done to model a polymer gel treatment pilot test without mechanical isolation, that was performed to improve the injection profiles and the sweep efficiency in a water injector well of an hexagonal pattern in the Lagomar field located in the Maracaibo Lake in western Venezuela.
The gel treatment pilot test was performed in the C-4 reservoir, a layered highly heterogeneous Eocene sandstone. In this reservoir water injection for secondary have been performed for over tree decades. High water cuts have forced management to shut in several producing wells.
A reservoir characterization analysis that included PLT logs, core analyses, and geomechanics, identified the presence of induced fractures as a cause of low sweep efficiency. Based on this reservoir study, a polymer gel treatment was designed for an injection well located in the center of a hexagonal well pattern.
A commercial gel polymer technology (MARCITsm) was selected to modify the injection profile in this pilot test. The results from the test injecting 3700 barrels of gel in the water injector well were very promising, showing an average reduction of 30% in water cut and 26,850 barrels of incremental oil five months after the treatment.
A reservoir simulation study was developed using STARS, a K-value compositional reservoir simulator with gel modelling capabilities. The model reproduces reasonably the performance observed in the field pilot test.
The simulation study is a first approach to developing a predictive tool to assist in the planning and design of future non selective gel treatments in water injector wells, applicable in the Lagomar field and analogous water injection projects.
Seismically Driven Improved Fractured Reservoir Characterization
Authors: Ouenes Ahmed , Zellou Abdel M. , Robinson Gary , Balogh Dave , Araktingi Udo 
Published: December 2007

Abstract
Characterization of naturally fractured reservoir is a recurring challenge for many oil and gas companies that manage and develop fractured reservoirs. Several techniques have been applied in the past to characterize these complex reservoirs; most of them have been proven unreliable. This paper will describe a methodology to improve the characterization of fractured reservoir using seismic attributes derived from pre-stack and post-stack high resolution inversion and spectral imaging.
The methodology presented in this paper uses the simultaneous integration of geophysical, geologic, and engineering data to improve the reservoir description. At the root of this reservoir characterization technique is the increasingly accurate seismic data collected on most of the reservoirs world-wide. Extensive use of this seismic information is made possible through the use of pre-stack high-resolution elastic inversion, post-stack high resolution inversion, and spectral imaging. These processes allow the derivation of seismic attributes that are extremely relevant to fracturing and could also be used as input in the continuous fracture modeling approach. Based on this seismically driven reservoir characterization, the fractured reservoir properties could be accurately estimated in 3D. An application of this technology and workflow is presented on a very complex fractured reservoir.
Forty Years of Improved Oil Recovery: Lessons from Low-Permeability Turbidites of the East Wilmington Field, California
Authors: Jenkins Creties , Al-Sharif Shahin , Harris Randy , Weisgram John , Michel Don 
Published: December 2007

Abstract
The U-P Ford zone in the Long Beach Unit of the East Wilmington Field consists of low-permeability (2-50 millidarcies) turbidites that have been waterflooded since field start-up. Forty years of successes and failures have provided valuable insights into how to best waterflood these reservoirs given their thin-bedded nature, lateral and vertical changes in reservoir quality, formation damage susceptibility, and sand control problems. Multiple techniques and technologies have been applied to describe their reservoir architecture, quantify reservoir performance, and extract the oil. This work has become more challenging as the waterflood has matured and will require the close integration of all disciplines to identify and exploit remaining opportunities.