bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Characterization and Dynamic Modeling in a Brownfield Carbonate Reservoir
Authors: Biswas Deepankar , Cron James W. 
Published: October 2009

Abstract
Understanding production behavior particularly from fractured carbonates has always been a challenge. The difficulty stems from the secondary porosity and permeability developments in carbonates in conjunction with the seemingly haphazard fracture presence in the midst of rapid and erratic facies changes sometimes within short distances. To make matters worse the spatial connectivity of these fractures complicates completion, pressure maintenance and improving sweep strategies. Therefore it is paramount to understand and characterize the fractured conduits and account for their importance in the overall development of the field. This paper discusses a systematic step-by-step methodology to build a geologic realization for a fractured reservoir and conduct dynamic simulations to calibrate and forecast various development scenarios.
The methodology encompasses geo-scientific work, engineering analysis, production diagnostics and reservoir simulation. Classic clustering analysis is used to augment results of production diagnostics to capture the effects of fracture dominated flow. Further, material balance utilizes early production and pressure history, during both undersaturated and saturated conditions, to provide bounds of in-place fluids. Petrophysical work analyzes available well logs to obtain matrix attributes and classify reservoir and non-reservoir types. The static model devises empirical transforms to distinguish various facies types. The facies types are stochastically populated in the inter-well region. A possible realization of the reservoir based on total-property approach is constructed. The reservoir model is then calibrated based on 25 years of production and some pressure history. Finally, various development scenarios are investigated.
The observations of clustering analysis is discussed and tied to the production behavior. The insights gained are shown to enhance calibration process. The integrated approach is demonstrated to unlock various uncertainties about in-place and recoverable reserves.
Significant contributions are: Clustering analysis4 in conjunction with production diagnostics to reveal the nature of the fracturesWeigh various development scenarios to unlock the myths of stereotypical development patternA way to learn more about the reservoir architecture and resident fluid movements to screen for upside potential
Improved Kick Management During MPD by Real-Time Pore-Pressure Estimation
Authors: Gravdal Jan Einar , Nikolaou Michael , Breyholtz Øyvind , Carlsen Liv A. 
Published: October 2009

AbstractPressure maintenance within safe bounds and minimization of influx of fluids from the formation to the well during a kick are basic concerns of well control. Managed Pressure Drilling (MPD) offers improved capabilities over conventional well control methods to address these concerns. In this work we develop a methodology that capitalizes on the improved access to down-hole measurements offered by wired drill pipe telemetry, to maintain pressure within desired bounds during kick management. The objective of this methodology is to improve MPD by reducing non productive time, reducing formation damage and optimizing operational limits for the annular back pressure choke manifold.The proposed methodology estimates formation pore pressure automatically based on real-time measurements when a gas kick is taken during MPD. The methodology relies on the characteristics of the pressure build-up curve. Implementation of the methodology presumes the availability of standard MPD equipment for automatic annular back pressure control.A representative North-Sea well is used as test case geometry and an advanced hydraulics model is used as a virtual well in computer simulations that provide the basis for the presented results.The proposed methodology is demonstrated to both maintain pressure within desirable bounds and reduce formation fluid influx during a kick and thereby prevent the risk of hole stability problems and the cost associated with non-productive time.
Integration of Well Test Pressure Data Into Heterogeneous Geological Reservoir Models
Authors: Li Gaoming , Han Mei , Banerjee R. , Reynolds A. C. 
Published: October 2009

Abstract
This paper presents the application of the ensemble Kalman filter (EnKF) method to the integration of well test data into heterogeneous reservoir models generated from geological and geophysical data. EnKF does not require computing the gradient of an objective function, and hence can be applied easily with any reservoir simulator, and more importantly, is far more efficient than a gradient-based history matching procedure when the forward model is represented by a reservoir simulator. In the procedure for integrating pressure transient data considered here, the static geological/geophysical data are assumed to be encapsulated in a multivariate probability density function characterized by a prior mean and covariance for the joint distribution of the porosity and permeability fields. As the prior mean of the property fields obtained from the core and log data can sometimes be erroneous, a partially doubly stochastic model is applied to account for the uncertainty of the prior mean. In the doubly stochastic model, a correction to the prior mean is adjusted together with the heterogeneous field during history matching. The method is tested with synthetic heterogeneous single-layer and two-layer reservoirs. Excellent data matches are obtained with EnKF in a small fraction of the time that would be required for a gradient-based history-matching process and the observed data fall within the uncertainty bounds of the ensemble data predictions. In the layered reservoir case, the uncertainty in rock property fields is further reduced by integration of production log data (layer flow rates). We show that problems of statistical inconsistency and poor data matches that are sometimes encountered when matching production data with EnKF do not occur when matching pressure data with the EnKF implementation used here. This undoubtedly occurs because the dynamical system (reservoir simulator equations) is much more nearly linear for the single-phase flow problems considered here than for multiphase flow cases.
Prediction of Slug Frequency for High Viscosity Oils in Horizontal Pipes
Authors: Gokcal B. , Al-Sarkhi A. S. , Sarica C. , Al-Safran E. M. 
Published: October 2009

Abstract
Slug frequency is defined as the number of slugs passing at a specific point along a pipeline over a certain period of time. Most experimental studies related to slug frequency in the literature were conducted using air and water. Data with a viscous liquid phase are scarce. Knowledge of the effect of liquid viscosity on slug flow is crucial to size pipelines and design pre-process equipment. In this study, the effects of high oil viscosity on slug frequency for horizontal pipes are experimentally investigated. The experiments are performed at oil viscosities between 0.181 and 0.589 Pa·s in a horizontal pipe. Experimental results are compared with the existing slug frequency correlations. Experimental observations reveal that slug frequency appears to be a strong function of liquid viscosity. However, existing slug frequency closure models do not show any explicit dependency on liquid viscosity. A closure model taking into account viscosity effects for horizontal pipes on slug frequency is proposed. The proposed slug frequency model is compared against published data. The comparison of proposed closure model against limited published data shows that it is a better alternative than existing correlations for high viscosity oils. The proposed slug frequency closure model can improve the performance of the existing mechanistic models for high viscosity oil applications.
Analytic Investigation of Convection During Conduction Heating of a Heavy-Oil Reservoir
Authors: Lawal Kazeem A. , Vesovic Velisa 
Published: October 2009

Abstract
The assumption of constant temperature is often valid for the operation and analysis of most conventional oil reservoirs; however the average behaviour of reservoirs exposed to thermal flooding is non-isothermal. In addition to being non-isothermal, heated reservoirs are characterised by non-uniform temperature distribution. Where the heating mechanism is conduction, most analyses ignore convection (including natural convection) in the overall heat balance. However, the induced temperature gradient affects fluid properties (especially viscosity and density) and their spatial distribution.
In this paper, possible buoyancy-induced natural convection is investigated by simulating one-dimensional vertical temperature profiles of a semi-infinite reservoir column, fully saturated with undersaturated heavy oil, subjected to conduction heating from the bottom. Using a realistic temperature dependence of the density and viscosity of typical Athabasca bitumen, vertical distributions of in-situ oil density, velocity and Nusselt number consistent with the induced temperature gradient are established. The simulation results indicate that at any time, oil density increases vertically away from the heat source, a condition that is gravitationally unstable, with a potential for fluid-redistribution, triggering convection. In this study, the magnitude of a Nusselt number is used as a proxy for the relative importance of natural convection. Although it is shown that free convection can be important, its significance depends on the duration of heating as well as rock and fluid properties. Consequently, we argue that the convective heat-transfer, in addition to temperature and time-dependent variations of oil density and viscosity, should be considered in realistic models of thermal recovery of heavy oil, even if the heating philosophy is "apparently" conduction.
Produced Water Separation at Unmanned Offshore Wellhead Platform: A Concept Report
Authors: Gupta Anil Kumar , Rai Ramashish , Kumar Ajit , Asija Narendra , Soni Dheeraj 
Published: October 2009

Abstract
In the mature producing offshore fields, managing water production is an important and critical aspect of the oil and gas production. Fields where topside processing facility has reached to its maximum handling capacity, installation of additional equipments require a new approach. Taking a clue from the latest profiles of Indian Offshore Assets which suggest increase in water cut of the order of 70% presently and rising up to 92% by 2030 overloading the process (separation and produced water conditioning) facilities at Process Platforms. This is where project on produced water separation at offshore wellhead platforms was taken up. Water separation at wellhead can be used to: Increase the oil production rate in a pipeline with a given diameterReduce capacity constraint at separator inletDevelop compact and low weight facilities for marginal topsides
With aim to minimize produced water handling at downstream of Wellhead Platform i.e. at process platform, free water is to be knocked out at WHP with ❖Minimum Wellfluid pressure reduction❖Minimum Floor Space❖Minimum Interference❖Maximum reliability
Recent developments have made possible separation system meeting strict requirements with respect to both performance and reliability. There are separators operating in subsea environment removing produced water from Wellfluid with desired results. In view of this, the present condition of Mumbai offshore field necessitates the deployment of such techniques in the ageing Mumbai High field as well.
This study focuses on produced water separation at offshore WHP and examines the factors affecting separation at unmanned WHP. The study also analyzes the impact of Produce Water Separation at WHP. The possible impacts envisaged are flow assurance, reduced backpressure on wells, wells deliverability, capacity constraint at the Separator inlet and Liquid handling at PWC system of Process Platform.
Laboratory Modelling of Equipment Erosion by Sand Particles
Authors: Graham Lachlan , Wong Chong Y. , Lester Daniel , Wu Jie 
Published: October 2009

Abstract
Impact by sand particles entrained in gas or oil product streams from down-hole well completions often causes erosive damage to the surface of sand filtration screens, heat exchangers, pipes, pipe bends, valves, gas compressors and other equipment. It is of major interest to develop designs to minimise the erosion damage. Erosion is often found to be unevenly distributed, for example erosion in a pipe elbow. Localized deep material loss or holing can lead to functional failure even though other areas of the component surface may be still undamaged. It was found that component design/geometry could often be modified to alter the flow field and even-out the erosion distribution, thus reducing the localized high erosion rate and extending the equipment service life. The optimization process can be most effectively carried out with assistance from erosion flow modelling. The objective of this paper is to describe the latest erosion flow modelling technique used at CSIRO, Australia. The technique consists of a combined laboratory physical modelling and computational fluid dynamics (CFD) approach. The physical modelling employs a paint modelling technique to illustrate the erosion patterns and advanced metrology for quantitative erosion measurements. Both of these data sets are also used to validate and improve CFD erosion modelling. The paper will show a series of case studies of erosion prediction and an example of erosion reduction through geometrical modifications with the materials used unchanged.
Minimum Miscibility Pressure Investigations for a Gas Injection EOR Project in Al Shaheen Field, Offshore Qatar
Authors: Mogensen K. , Hood P. , Lindeloff N. , Frank S. , Noman R. 
Published: October 2009

AbstractGas injection as an EOR method is being considered for the giant Al Shaheen field, located offshore Qatar. The field is characterized by large lateral variations in fluid properties; the oil gravity ranges from 16 to 38 °API and significant variations in initial GOR and saturation pressure are observed.An extensive experimental program aimed at establishing the miscibility behaviour for this complex fluid system has been performed. Experiments included a range of gas injection tests such as swelling and multi-contact miscibility tests, enrichment studies and slimtube measurements. The miscibility behaviour across the range of oil gravities has been very well captured with a single equation of state (EOS) model, as described by Lindeloff et al. (2008).Slimtube measurements are the preferred method for establishing minimum miscibility pressures experimentally as condensing/vaporizing effects can be captured in this setup. The physical dispersion of the slimtube was characterized by a specially designed experiment using first-contact miscible (FCM) fluids. The results of the FCM experiments were used to determine the degree of numerical dispersion required in a 1D slimtube simulation model to match the measured data. An extrapolation towards an infinite number of cells was then performed to estimate the dispersion-free minimum miscibility pressure (MMP) from the slimtube experiments conducted on live reservoir oil using carbon dioxide as injection gas.In addition to the slimtube simulations, several algorithms for estimating the minimum miscibility pressure have been compared; some are empirical correlations, others are based on analytical gas injection theory using the method of characteristics (MOC) limiting tie-line method and the last one relies on a mixing-cell approach. The advantages and drawbacks of each approach are discussed, and the results are compared to laboratory data. In general, there is a very large spread in predicted MMP using carbon dioxide as injection gas. Empirical correlations generally overpredict the MMP for light oils and underestimate the MMP for heavy oils. Various key tie-line methods using the same tuned EOS model provide very different estimates of the MMP and some of them exhibit convergence problems. The results of the present work suggest that the mixing-cell model provides the most robust estimate of MMP over a large range of oil compositions, subject to EOS description. In essence, there is currently no prediction method that can replace the slimtube experiments.
A Comprehensive Methodology to Avoid and Remediate Drilling Problems by Real Time PWD Data Interpretation
Authors: Gandelman R. A. , Martins A. L. , Teixeira G. T. , Waldmann A. T. A. , Mari A. D. , Rezende M. S. C. , Aragão A. F. L. 
Published: October 2009

Abstract
Drilling offshore oilwells is a very expensive and complex job, in which all efforts must be spent to keep the annular pressure between a minimum (pore pressure) and a maximum pressure (frac pressure). A lot has been invested in downhole sensors and data transmission systems but there is a common sense in the industry that very little is available in real time data interpretation. The correct interpretation of PWD (Pressure While Drilling) data is a very powerful tool to identify undesired phenomena. The anticipation and remediation of potential hole problems is an ultimate goal of most real time measurement devices installed on drilling rigs. The accurate quantification of the phenomena that impact bottom hole pressures is a must on anticipation operational problems. This paper presents a comprehensive methodology to accurately quantify some of the most common phenomena that occur during the drilling job. Transient modeling, pattern recognition and AI strategies were considered. The final goal is the development of a real time computational tool to interpret the operational parameters, identify and remediate problems, reducing risks, time and costs.
Examples of problems detection (such as cuttings excessive accumulation, kicks, wash outs, hydraulic packers, instability related issues, etc) will be addressed. Besides, the impact of remedial actions on downhole pressures and solids concentration profiles will be also detailed.
Preventing Hole Enlargement While Drilling Heavy Offshore Oil Reservoirs
Authors: Ferreira M. V. D. , Da Costa F. G. , Campos E. F. , Macedo F. S. , Aragão A. F. L. , Martins A. L. 
Published: October 2009

Abstract
The development of heavy oil fields imposes several challenges for well construction: in order to guarantee minimum flow rates, long horizontals intervals are often required. Long horizontals are associated to long reservoir exposure times which can affect final open hole quality. Rock fluid interaction issues and BHA design directly affect the drilling of sensitive formations, such as non consolidated heavy oil reservoirs.
This article presents initially a comprehensive data analysis of caliper logs in offshore heavy oil wells drilled in Brazil. The analysis correlates hole enlargement with relevant parameters such as fluid type, flow regime and BHA composition. Data sources considered were real time monitoring equipment, logging data and drilling reports. Results indicate that water based fluids and turbulence proved to stimulate hole enlargement and should be avoided.
The study is also supported by a unique experimental work where fluid flow conditions were simulated in a pilot unit where the wellbore was represented by a non consolidated synthetic core saturated with high viscosity oil. For a given flow rate, hole enlargement is monitored with time by a real time CT scanning technique. Experimental results are in agreement with field observations. The role of drillstring composition was not contemplated in the experimental study.
Cemented Ball-Activated Sliding Sleeves Improve Well Economics and Efficiency
Authors: Bozeman Timothy , Degner Dennis 
Published: October 2009

Abstract
This paper examines the effectiveness of a completion technique where ball-activated sliding sleeves (BASS) are cemented into the wellbore. This technique allows operators to change zones between fracture-stimulation treatments by dropping balls from surface, instead of using the conventional pumpdown plug and perforating method. A five-well group completed with this method is compared to its direct offsets that were completed conventionally to draw conclusions. Initial studies show that this completion method reduces the time and cost to complete a horizontal well while yielding production that is equivalent to or better than the offset wells.
Preliminary research shows that the BASS group average 30-day Initial Production (IP) was approximately 25% better than the offset well average, and that the 9-month IP was approximately 33% better than the offset well average. Using the ball-drop completion technique, production increases were accompanied by faster completion times, a reduction in required hydraulic horsepower (HHP), and substantial cost savings. On average, wells that were completed using the cemented BASS showed no cost increase during the drilling phase, and reduced the mechanical completion cost by $20,000 to $40,000 per well when compared to offset wells. The primary efficiency driver during completion is the ability to prepare the well for fracture stimulation and complete multiple stages of fracture stimulation without having to utilize a workover unit. Additional time savings occurs between fracture-stimulation treatments; this method reduces downtime between stages from 3 hours to 20 minutes. This time savings can lead to more efficient use of equipment, which benefits the operator and the pumping company and improves community relations.
Salt Drilling While Underreaming Behaviors Illuminated by Distributed Downhole Measurements
Authors: Kull Bobbie Jo , Duff Richard G. , Clarke Alan J. , Perez Daniel G. , Stuart Simon M. 
Published: October 2009

Abstract
Many developments in the deepwater Gulf of Mexico target reservoirs are below salt sections. As well plans increasingly call for drilling through long salt sections; a common strategy in the Gulf of Mexico is to drill while simultaneously opening the hole with an under-reaming tool. This configuration presents unique dynamic behaviors to the drilling system. Understanding the drilling system is important in order to reduce vibrations and to meet desired run lengths. In the Gulf of Mexico dynamics have limited the effectiveness and life of hole opening tools. Therefore, the identification of drillstring dynamic behavior is critical to efficiently executing well plans that call for under-reaming while drilling.
To study the vibration phenomenon unique to under-reaming while drilling bottomhole assembly dynamics through salt sections the operator employed a unique distributed downhole measurement system which included vibration sensors. The goals of this study were to evaluate the accountability of the real-time MWD and surface data, to illuminate complex dynamics and provide further stimulus for the development and adoption of real-time strategies. The distributed measurement system generated insights in all three areas.
This paper presents examples of specific dynamic behaviors from several deepwater Gulf of Mexico wells, focusing on the drilling phenomenon occurring in salt. Key observations about the development of vibrations while opening the reamer, drilling, drilling transitions and back reaming are given. Attenuation of vibration to the surface is demonstrated. Predrill modeling of bottomhole assemblies was also cross-validated. The impact of cutting structure effectiveness and bottomhole assembly "neutral point management" is also highlighted with examples.