bluuebunny/crossref_metadata_2025_split huggingface dataset:
3D Geological Modeling in a Turbidite System with Complex Stratigraphic-Structural Framework—An Example From Campos Basin, Brazil
Authors: Albertão G. A. , Grell A. P. , Badolato D. , dos Santos L. R. 
Published: December 2007

Abstract
After 3 years of production, results indicated necessity to refine the geological model of Cretaceous turbidite reservoirs in an off-shore oil field of Campos Basin, Brazil.
A stratigraphic analysis was developed to build a new stratigraphic-structural framework. Seismic interpretation was used to incorporate structural data by mapping the system of normal faults. Using concepts of sequence stratigraphy, seismic, biostratigraphic and lithologic data were used to define 12 major depositional sequences, spanning from Cenomanian to Maastrichtian. In 8 of these sequences, 12 turbidite systems were recognized and 9 of them focused for the present study. These turbidite systems compose the operational reservoir zones. Six of them were deposited during the Turonian and three during the Santonian. Erosive surfaces and regional unconformities affect the distribution of the turbidite systems. Action of erosion and faulting results in complex framework and lateral communications among reservoirs of different ages. Several oil-water contacts are present and controlled by some of the faults and the lateral communications.
Modeling this complex system included many different techniques and softwares in steps of the work. The first step involved a topologic three-dimensional construction, including all of the major geologic information; relationships among the main turbidite systems were validated by production data. Next was creating a refined grid to populate the model with rock-properties; corner point geometry grid was built to honor the direction of major faults. Third was facies characterization; vertical proportion matrix was used to represent the horizontal non-stationary of the data and seismic amplitude was used as a constraint. Plurigaussian simulations were used to populate the model; this type of simulation is suitable to represent the multiple and non-sequential contact relations among facies. The fifth step was using Monte Carlo simulation to fulfill the model with porosity and permeability, based on petrophysic histograms from well data, classified by facies. Upscaling the model was the last step in order to finally transfer the geological data to the flow simulator.
Preliminary results from the flow simulator reveal better fitting between this new geological model and the present production data.
Analysis of Gas-Cycling Performance in Gas/Condensate Reservoirs Using Neuro-Simulation
Authors: Ayala L. F. , Ertekin T. 
Published: December 2007

Abstract
The study of gas-condensate reservoirs has been a fertile area of research in the last decades, especially because of their singular depletion behavior which cast them apart from other types of oil and gas reservoirs. Typically, exploiting a gas-condensate reservoir without pressure maintenance generates high surface gas recoveries with relatively low condensate recoveries. Appearance of a hydrocarbon liquid phase upon isothermal depletion is typical of these systems, and major concerns arise related to the loss of this valuable fraction of heavier hydrocarbons and the associated impartment in gas production around the wellbore region. As a consequence, the injection of either surface gas or other gases such as nitrogen is common for pressure maintenance purposes. Pressure maintenance is economically justified by keeping the reservoir pressure above dew point or revaporizing any valuable condensate that might have formed. The convenience of the gas injection operation for a specific gas-condensate reservoir is strongly tied to the flow characteristics of the reservoir and phase behavior of the fluid. Highly sophisticated and expensive compositional simulations are usually employed in order to calculate reservoir performance under gas-cycling operations. In this study, we propose the implementation of artificial neural network (ANN) technology towards the establishment of an expert system capable of learning the existing vaguely understood relationships between the input parameters and output response of compositional simulation of gas-cycling operations in gas-condensate reservoirs. Parametric studies are conducted which identify the most influential reservoir and fluid characteristics in the establishment of optimum production protocols for the implementation of the pressure maintenance operation. As a result, a powerful tool for the implementation of pressure maintenance operations in gas-condensate reservoirs is developed. This tool is capable of assisting in designing an optimized exploitation scheme for a particular reservoir under consideration for development. Fast, reliable, and inexpensive results are obtained using the proposed approach while capturing the important flow and thermodynamic characteristics inherent to such systems without resorting to detailed and expensive compositional simulation studies.
The Quest for Improved Proppant Placement: Investigation of the Effects of Proppant Slurry Component Properties on Transport
Authors: Brannon H. , Wood B. , Wheeler R. 
Published: December 2007

Abstract
Beyond the initial fracture propagation, the primary function of fracturing fluids is to provide the means and media for the transport and placement of a conductive proppant pack in the created fracture such that resident hydrocarbons may be more easily produced. That is after all, the objective of hydraulic fracture stimulation. Fracturing fluids have undergone great scrutiny in recent years, leading to significant effort and expense expended in the quest to develop the "perfect" system. Historically, these efforts have been akin to the proverbial dog chasing his tail, rather than on addressing the engineering objective of the designated location of a conductive propped fracture. Primary development focus has been on optimization of fluid rheological stability to get the treatment "in the hole" and then, secondarily, on mitigating the damage caused by "new and improved" fluid system. Unfortunately, post-stimulation production analysis frequently demonstrates effective fracture area far less than that designed, suggesting either that the proppant-pack is damaged far more than expected or that the proppant was not placed in designated areal location. The latter could be due to inadequacies in terms of the lateral transport away from the wellbore (length) and/or in vertically covering the productive interval (height).
Many low permeability reservoirs are now experiencing a renaissance in the application of high rate slickwater fracs. The slickwater treatments are typically designed for long fracture lengths even though such fluids are thought to have inherently poor proppant transport abilities, hence the high rate.
Recent testing was conducted in a large-scale slot apparatus to evaluate the relative effects of proppant slurry component characteristics and the proppant transport capability. The effects of various fluid specific gravity, fluid viscosity, proppant specific gravity, proppant size, slurry flow rate, and slot width were investigated. Testing included fluids from slickwater to gelled, weighted brines, proppants from 40/70 Ottawa sand to 14/30 ultra-lightweight proppants, pump rates from 0.1 to 1.0 bbl/ft/min, and slot widths from 0.25 to 0.5 inch. This paper will provide evaluation of the proppant transport testing data and discuss the comparative abilities of current fracturing slurry system technologies to achieve placement of a productive propped fracture.
Value-Based Allocation and Value Adjustment on Mixed-Quality Commingled Natural Gas Pipelines
Authors: Telesford A. L. , Telesford A. L. 
Published: December 2007

Abstract
This paper presents an insight into the thorny issue of ensuring, through allocation and value adjustment, that parties on a joint or commingled system receive their share of the thoroughly mixed end products and proposes a novel methodology for accomplishing this in an operable and equitable manner.
Prediction of Sand Production Rate in Oil and Gas Reservoirs: Field Validation and Practical Use
Authors: van den Hoek P. J. , Geilikman M. B. 
Published: December 2007

Abstract
This paper presents a model for the prediction of sand volumes and rates for any type of clastic oil or gas reservoir. This model captures both the geomechanical aspects (rock deformation and failure) and the transport aspects (e.g. role of drawdown and watercut) of the sand production problem.
An extensive model validation is presented in which the predicted sand volumes and rates are compared with field observations for a variety of oil and gas fields under various stages of depletion. For all these cases, the model predictions and field observations are in reasonable to good agreement.
In addition, a discussion is presented on how the model can be practically used. This discussion clearly demonstrates that sand production behaviour is not only dependent on in-situ stress, rock strength, and drawdown, but also very much on how the field is actually operated / managed at a detailed level.
A New Concept of Chemical Sand Consolidation: From Idea and Laboratory Qualification to Field Application
Authors: Kotlar H. K. , Haavind F. , Springer M. , Bekkelund S. S. , Torsæter O. 
Published: December 2007

Abstract
The conceptual idea is to give the porous matrix of the formation some additional residual strength to enhance the maximum sand free rate (MSFR).
Sand production in weakly consolidated reservoirs will occur when tensions in the well/perforation tunnel walls are large enough to disrupt the binding between the individual sand grains. This will generate a plasticized layer of sand in the near well bore area. The layer will erode by the produced fluid and be transported to the surface. The rate of erosion will depend on the residual strength of the plasticized zone and of the hydrodynamic forces acting on that particular zone.
There is field evidence indicating a residual strength corresponding to the capillary force in water-wet sand to be sufficient in stopping or limiting the sand production substantially. Thus, only a small increase in residual strength of the plasticized sand would make large contribution for enhancing the MSFR. This will have large economical implications in fields with wells controlled by MSFR, and particularly in the decline phase in which the field is well controlled by the well potential.
Since the criteria for strength are quite low, search for potential treatment chemicals could be carried out in areas completely different from the traditional chemicals used in sand consolidation. Three different chemical systems have been investigated and one chemical has been brought further for laboratory qualification and field use at a North Sea Field.
In order to carry out a full field test, challenges regarding water contamination, long horizontal wells with difficult placement and zonal coverage, and complex polymerization mechanisms in the carrier fluid had to be addressed. Some of these challenges and field experiences will be presented and discussed to gain valuable knowledge for future chemical sand consolidation operations.
New High-Performance Completion Packer Selection and Deployment for Holstein and Mad Dog Deepwater Gulf of Mexico Projects
Authors: Fitzgerald A. , Harpley G. , Hupp J. , King J. G. 
Published: December 2007

Abstract
The BP Holstein and Mad Dog oilfields in the Gulf of Mexico are high-profile deepwater projects (4,300 and 4,400 ft water depth) with high production and high costs. Wellbore construction for both fields includesd a completion packer to manage tubing loads and reliably isolate production fluid and pressures from the casing, tiebacks, and risers.
Several drivers influenced the packer selection and development process. The magnitude of the packer loading pointed toward high-performance permanent packers. Life- of- well and life- of -field requirements for possible planned and unplanned workovers pointed toward the operational flexibility of retrievable packers. High rig costs, a desire for accelerated production, and difficult wireline access "S" curve wells indicated the value derivable from interventionless completions. And the high cost of failure pointed toward high performance and quality standards to reduce risk of failure and potential malfunctions. Together, these drivers pointed toward a new packer solution. Ultimately a high- performance, modular, removeable, "V0 rated," interventionless production packer was developed which met all of these criteria. This paper describes the Mad Dog Holstein and Mad Dog Holstein completion environment, and details the selection, development, deployment, and lessons learned with the hydrostatic set, interventionless, removeable packer solution.
Optimizing the SAGD Process in Three Major Canadian Oil-Sands Areas
Authors: Shin H. , Polikar M. 
Published: December 2007

Abstract
The SAGD process has already been implemented for commercial production in Alberta. In this study, SAGD operating conditions were optimized through numerical reservoir simulations in the three oil sands areas using characteristic properties. Several parameters were screened to define the most applicable reservoir conditions for the SAGD process. The product of reservoir thickness and permeability (k×h) was found to be the single most important parameter. Finally, the optimal cases for each area were compared.
The simulation results for shallow Athabasca-type reservoirs showed that a net pay thickness of 15 m is still economic for the SAGD process because of the high permeability of this type of reservoir, despite the very high bitumen viscosity at reservoir conditions. For Cold Lake-type reservoirs, a net pay thickness of at least 20 m is required for an economic SAGD implementation. In Peace River-type reservoirs, net pay thicker than 30 m might be required for a successful SAGD performance due to the low permeability of this type of reservoir.
The results of the study indicate that the shallow Athabasca-type reservoir, which is thick with high permeability (high k×h), is a good candidate for SAGD application, whereas Cold Lake and Peace River-type reservoirs, which are thin with low permeability, are not as good candidates for conventional SAGD implementation.
Optimal Coarsening of 3D Reservoir Models for Flow Simulation
Authors: King M. J. , Burn K. S. , Wang P. , Muralidharan V. , Alvarado F. , Ma X. , Datta-Gupta A. 
Published: December 2007

Abstract
We have developed a new constrained optimization approach to the coarsening of 3D reservoir models for flow simulation. The optimization maximally preserves a statistical measure of the heterogeneity of a fine scale model. Constraints arise from the reservoir fluids, well locations, pay/non-pay juxtaposition, and large scale reservoir structure and stratigraphy. The approach has been validated for a number of oil and gas projects, where flow simulation through the coarsened model is shown to provide an excellent approximation to high resolution calculations performed in the original model.
The optimal layer coarsening is related to the analyses of Li and Beckner (2000), Li, Cullick and Lake (1995), and Testerman (1962). It differs by utilizing a more accurate measure of reservoir heterogeneity and by being based on recursive sequential coarsening, instead of sequential refinement. Recursive coarsening is shown to be significantly faster than refinement: the cost of the calculation scales as (NX·NY·NZ) instead of (NX·NY·NZ)[2]. The more accurate measure of reservoir heterogeneity is very important; it provides a more conservative estimate of the optimal number of layers than the analysis of Li et.al.. The latter is shown to be too aggressive and does not preserve important aspects of the reservoir heterogeneity. Our approach also differs from the global methods of Stern (1999) and Durlofsky (1994). It does not require the calculation of a global pressure solution and it does not require the imposition of large scale flow fields, which may bias the analysis, Fincham (2004). Instead, global flow calculations are retained only to validate the reservoir coarsening.
Our approach can generate highly unstructured, variable resolution, computational grids. The layering scheme for these grids follows from the statistical analysis of the reservoir heterogeneity. Locally variable resolution follows from the constraints (reservoir structure, faults, well locations, fluids, pay/non-pay juxtaposition). Our reservoir simulator has been modified to allow a fine scale model to be initialized and further coarsened at run time. This has many advantages in that it provides both simplified and powerful workflows, which allow engineers and geoscientists to work with identical shared models.
Streamline-Based Production-Data Integration in Fractured-Reservoir Characterization and Its Application
Authors: Shen F. , Li S. 
Published: December 2007

Abstract
An integrated fracture modeling process is developed by incorporating different disciplines and scales from static data reservoir characterization to streamline-based dynamic data calibration. The geometry and continuity of reservoir properties need to be modeled before characterizing fractures. The geological structure based geomechanical analysis, rock physics modeling and azimuthal seismic anisotropy techniques are applied to deriving strain and stress properties, seismic anisotropy. The fracture orientations and density can be identified with these attributes and validated in wells with image logs. The obtained fracture distribution is translated into fracture properties at wells by incorporating geo-mechanical in-suit stress information to identify open fractures and to determine the effective fracture aperture. The spatial geo-mechanical information is useful in predicting the variations of fracture aperture. The coupling flow between the fractures and matrix is considered in the modeling of initial effective permeability tensor. The streamline based flow simulation is performed to match observed reservoir pressure responses at wells. The inferred permeability field can be used to examine the orientations of the major directional flow. By comparing to the fracture distributions characterized with static data, the fracture spatial connectivity can be calibrated. The calibration of fracture permeability is proved to be an efficient way to characterize the complexity of nature fracture system. Streamline simulator can efficiently handle large reservoir models. The application of the modeling process to the case study shows that this is a significant step toward making dynamic data integration in fractured reservoir characterization.
Downhole pH Measurement for WBM Contamination Monitoring and Transition Zone Characterization
Authors: Raghuraman B. , Xian C. , Carnegie A. , Lecerf B. , Stewart L. , Gustavson G. , Abdou M. K. , Hosani A. , Dawoud A. , Mahdi A. , Ruefer S. 
Published: December 2007

Abstract
Formation water sampling is important for understanding corrosion and scaling potential of the water, characterizing hydrocarbon/water transition zones, determining compatibility between injection water and formation water, and determining optimal salinity and pH windows for polymer and gel injections. To obtain good quality formation water samples with wireline formation testers in wells drilled with water-base mud (WBM), it is important to track mud filtrate contamination by distinguishing between formation water and mud filtrate in real time while sampling. Current techniques typically use a resistivity sensor to monitor this contamination in real time. However, this works only when there is sufficient resistivity contrast between the filtrate and the formation water. Another technique involves addition of a colored tracer dye to the drilling mud and then monitoring the tracer concentration with an optical detector in real time.
In this paper, we present results from a Middle East production well in which a new downhole pH measurement sensor was deployed on a formation wireline tester. The sensor uses pH-sensitive dyes that change color according to the pH of the water sample. The pH of the formation water is a key water chemistry parameter that can alter because of temperature and pressure changes surrounding the sample as it is brought to surface. Hence, to obtain accurate values, pH must be measured in real time at downhole reservoir conditions. In addition to successfully measuring pH downhole, results from this field test show that pH can also be used to qualitatively monitor mud filtrate contamination in real time. This takes advantage of the fact that the mud filtrate pH is typically much higher than the pH of formation waters. Multiple pH measurements during sampling showed a good match with cleanup trends determined independently using a colored tracer added to the mud. Simulations using some typical formation water and mud filtrate samples indicate that the pH dependence on contamination is a complex function depending on several factors including composition, buffer capacity, ion equilibria, ionic strength, temperature, and pressure. This makes quantitative estimation of contamination from pH measurements difficult; nevertheless, qualitative tracking of cleanup trends is possible and useful.
The ability to differentiate between formation water and mud filtrate pH is also useful in characterizing oil/water transition zones and delineating oil/water contacts by scanning formation fluid samples at different depths.
Both of these downhole pH measurement applications improve the efficiency and success rate of sampling with wireline formation testers.
Incorporating 4D Seismic Data in Reservoir Simulation Models Using Ensemble Kalman Filter
Authors: Skjervheim J. -A. , Evensen G. , Aanonsen S. I. , Ruud B. O. , Johansen T. A. 
Published: December 2007

Summary
A method based on the ensemble Kalman filter (EnKF) for continuous model updating with respect to the combination of production data and 4D seismic data is presented. When the seismic data are given as a difference between two surveys, a combination of the ensemble Kalman filter and the ensemble Kalman smoother has to be applied. Also, special care has to be taken because of the large amount of data assimilated. Still, the method is completely recursive, with little additional cost compared to the traditional EnKF. The model system consists of a commercial reservoir simulator coupled to a rock physics and seismic modelling software. Both static variables (porosity, permeability, rock physic parameters, etc.) and dynamic variables (saturations and pressures) may be updated continuously with time based on the information contained in the assimilated measurements. The method is applied to a synthetic model and a real field case from the North Sea. In both cases, the 4D seismic data are different variations of inverted seismic. For the synthetic case, it is shown that the introduction of seismic data gives a much better estimate of reservoir permeability. For the field case, the introduction of seismic data gives a very different permeability field than using only production data, while retaining the production match.