bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prediction of Sand Production Rate in Oil and Gas Reservoirs
Authors: van den Hoek P. J. , Geilikman M. B. 
Published: December 2007

Abstract
Most sand production prediction models to date have the capability to indicate whether initial sand production may take place somewehere during the lifetime of a reservoir. However, these models are unable to predict whether the sand production will be ‘problematic’ (e.g. in terms of erosion, plugging, well sand-up, separator fill, etc.), in particular for systems that have some tolerance towards sand production.
In order to predict whether sand production will be ‘problematic’, one needs to be able to estimate sand production volumes and rates as a function of, amongst others, bottom-hole load conditions, drawdown, and time. This paper presents a model for the prediction of sand production volumes and rates for any type of clastic oil or gas reservoir. This work builds on successful previous efforts to predict sand production rate in the Canadian heavy oil sands. The current model is a validation of the previous model and its further generalisation to sandstones of any strength (not just unconsolidated) with any reservoir fluid (not just heavy oil), and involves features such as failure of intact sand, post-failure cavity stabilisation, and non-associated viscoplasticity. The model has been calibrated to laboratory experiments.
Predicting and Managing Sand Production: A New Strategy
Authors: Palmer Ian , Vaziri Hans , Willson Stephen , Moschovidis Zissis , Cameron John , Ispas Ion 
Published: December 2007

Abstract
Sand prediction at BP has been developed by dividing it into three parts: (1) onset, (2) transient sanding, (3) steady-state sanding. For example, as drawdown is increased in a well in a sand-prone formation, significant sanding begins at some point (the onset), and this is followed by a transient sand burst, which may last hours or days or months. The sanding eventually declines to a background level (steady-state), in the range 1–100 pptb. We have made recent step-changes in (2) and (3), and we now have a tool that can predict sanding onset, and volumes during any stage of a well's production history, or even injection history.
The onset of sanding is predicted using a stress-based model. This model is conservative, based on a benchmarking study of field applications. One application predicts sanding in water injectors during shut-in, and recommends not using sand control. Another application explains delayed sanding in an HPHT gas reservoir, in terms of restraining forces due to capillary cohesion (i.e., the damp sand effect at the beach). The transient sanding model is a fully-coupled finite element (FE) model. The model has successfully predicted sand volumes in laboratory and field tests. With this model, we can judge whether we can manage the produced sand, from both production and injection wells. Finally, we have applied this to predict whether a well will kill itself after a blowout, due to sand in the wellbore increasing the hydrostatic pressure.
The steady-state model is an empirical model that is based upon extensive tests of sanding from cores in the laboratory. The model has been applied to predict sanding in an offshore field, and this has led to the conclusion that sand rates can be managed at surface, without sand control: a huge economic advantage. Finally, we present a case history where we use all three models to make an integrated prediction of onset, transient, and steady-state sanding, and find quite good agreement with field observations. In summary, the new three-fold strategy of sand prediction at BP has significantly increased our capability to predict sanding in production or injection wells. This quantum leap is invaluable to help decide if we can manage the sand at surface (or if downhole sand control is required); to decide if we can defer sand control until a later date (possibly increasing production as well as saving completion costs); to decide how much sand will be produced if we increase the drawdown in a sand-prone well; and even decide if we need sand control in water injectors.
Well Performance with Operating Limits under Reservoir and Completion Uncertainties
Authors: Wehunt C. D. 
Published: December 2007

Abstract
This paper shows how to evaluate well performance under conditions of reservoir and completion uncertainty, while also considering the impact of completion decisions and operating constraints. This topic is important because it can help to reconcile the often-large gap between theoretical, short-term deliverability, and reliable, sustainable performance.
A table of operating constraints is presented, with examples regarding application of some of the constraints. This constraint table also includes consideration for the type of surveillance that is needed to apply the constraints. Discussion within the paper shows that the most appropriate types of operating constraints are often not being used. This paper also addresses appropriate operating limits for completions with sand control installed.
Completion selection and design influence operating constraints. Examples within the paper illustrate methods to determine appropriate operating constraints. The examples also demonstrate the potential advantage of frac-packed completions or long horizontal completions with regard to preventing fines migration and increasing longevity.
To aid with probabilistic performance forecasting, the paper includes a tabulation of published skin values, including permeability data when it was available.
Improvements in Single-Phase Paraffin Deposition Modeling
Authors: Hernandez O. C. , Hensley H. , Sarica C. , Brill J. P. , Volk M. , Delle-case E. 
Published: December 2007

Abstract
Paraffin deposition under single-phase flow conditions was investigated to determine its dependence on shear stripping, deposit aging, flow regime, temperature gradient and fluid properties.
In this study, a new model for the prediction of singlephase wax deposition has been developed. Most of the models previously used assume that equilibrium exists at the deposit-fluid interface. A kinetic resistance of the fluid is considered in the new model. Therefore, the interfacial wax concentration might be different from the equilibrium wax concentration. The model also includes continuous diffusion of wax into the deposit. We believe that this enrichment of the deposit is responsible for the increasing hardness of the deposit with time, a process known as aging. The effect of shear stripping may also be incorporated in the prediction.
The model predictions are compared with predictions from previous models, as well as with experimental data gathered at the Tulsa University Paraffin Deposition Projects with two different oils: a black oil and a condensate. Even though some tuning is required for each oil, the new model is based on physical phenomena, reducing the empiricism of previous models.
A Novel System That Diverts Away From Water Zone: Successful Case Histories from the CNOOC Field in Java Sea - Indonesia
Authors: Soekama Robianto , Winarmo Mulad Budi , Halim Sunarto , Siddiqui M. Irfan , Dharmawan Arief , Placio Fransisco , Tibbles Raymond J. 
Published: December 2007

Abstract
Getting good acid diversion in high water cut wells is always a challenge. Relative permeability effects due to high water saturations will push the aqueous base treating fluid into zones with high water cut. This leaves the oil zones untreated and results in dramatic increases in post stimulation water production.. While many fluid diversion techniques exist, this paper focuses on the successful application and results of a novel Viscoelastic Surfactant (VES) based fluid used as diverter in matrix stimulation treatments performed by CNOOC in its Java Sea, Indonesia wells.
Innovative Well Completion Harnesses Deep, Hot South Texas Gas
Authors: Moe G. R. , Johnson Carl K. , Ingle Ray , Smith Robert C. 
Published: December 2007

Abstract
Efficient access to multiple permeable natural gas zones located in deep, over pressured, and extremely corrosive environments presents a challenge for South Texas operating companies. An innovative completion technique, featuring corrosion resistant alloy (CRA) tubulars has been effectively implemented by blending features of monobore, slim-hole, and conventional completion geometries.
A New Model to Obtain Representative Field Relative Permeability for Reservoirs Produced under Solution Gas Drive
Authors: Bauget F. , Egermann P. , Lenormand R. 
Published: December 2007

Abstract
The relative permeability curves (Kr) control the production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood) the Kr curves obtained in laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution gas drive (depressurized field, foamy oils), the experiments conducted in laboratory depend on the depletion rate and cannot be used directly for reservoir simulations.
We have developed a novel approach for calculating representative field-relative permeabilities. This new method is based on a physical model, which takes into account the various mechanisms of the process: bubble nucleation (preexisting bubbles model), phase transfer (volumic transfer function), gas displacement (bubbles flow). In our model, we have identified a very few number of "invariant" parameters that are not sensitive to depletion rate and are specific of the rock-fluids system (mainly the preexisting bubble size distribution and a factor between gas velocity and oil velocity in the dispersed phase regime). These invariant parameters are determined by history matching of one experiment at a given depletion rate.
The calibrated model is then used to generate synthetic data at any depletion rate, and especially at very low depletion rates representative of the reservoir conditions. Relative permeability are derived from these "numerical" experiments in the same way as real experiments. The calculated Kr are finally introduced in commercial reservoir simulators.
We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with a very good accuracy.
Finally, we present an example of determination of relative permeabilities at reservoir depletion rates.
Experimental and Theoretical Basis for a Wettability-Interfacial Area-Relative Permeability Relationship
Authors: Gladkikh Mikhail , Jain Vivek , Bryant Steven , Sharma Mukul 
Published: December 2007

Abstract
Using an interfacial tracer technique, our experiments show qualitatively different trends of total interfacial area between the wetting and non-wetting phases as a function of saturation, depending on whether the system is strongly or weakly wetted. A strongly wetted system is defined as one in which the wetting phase can spread as a thin film on the solid surface. We assess the relative contributions of fluid/fluid and fluid/solid interfaces to the total area using thermodynamic arguments. The fluid/solid contribution to area plays a crucial role in explaining the measurements.
The influence of interfacial area on relative permeability is not straightforward. Simple analysis based upon pore-level distribution of phases in a model porous medium allows quantifying the differences in the relative permeabilities for both weakly and strongly wetted systems, measured simultaneously with the interfacial area. Relative permeability correlates with fluid/solid area but not with fluid/fluid interfacial area.
Estimation of Flow Functions During Drainage Using Genetic Algorithm
Authors: Sun Xuefei , Mohanty Kishore K. 
Published: December 2007

Abstract
Unsteady state relative permeability experiment followed by automatic history matching has been used in the past for estimating relative permeability and capillary pressure simultaneously. The performance of the automatic history matching largely depends on the simulator, the functional form of the flow functions, and the optimization tool. Newton method, which is commonly taken as the optimization tool for the automatic history matching, may not converge to the global extremum in the presence of high non-linearity. Genetic algorithm (GA) with better global convergence property was used as the optimization tool in this work. Another advantage of GA as an optimization tool is that it requires only function evaluations for the solution searching and not Jacobian or gradient calculations as required by the Newton method. Corey model and piece-wise spline interpolation were utilized to represent the relative permeability. A new coding method in genetic algorithm was developed for piece-wise spline interpolation. In situ saturation data were collected during an unsteady state primary drainage experiment by CT-scanning. Simulation and experimental data were used to test the performance of the algorithm. Test results showed a good match between the simulation data and experimental data for low injection rate primary drainage.
Pore-to-Field Scale Modeling of WAG
Authors: Kløv T. , Øren P. E. , Stensen J. Å. , Lerdahl T. R. , Berge L. I. , Bakke S. , Boassen T. , Virnovsky G. 
Published: December 2007

Abstract
The paper describes an integrated pore-to-field scale modeling method of multiphase flow in porous media. Although the method is general, we demonstrate its power and versatility by modeling a WAG process in the Etive formation in a North Sea oil field. The method aims at capturing the relevant flow physics at different scales. Pore scale physics (µm-scale) is accounted for through predictive pore scale modeling of relative permeability and capillary pressure. The computed rock curves (cm-scale) are used to populate detailed geological models with a plausible spatial distribution of constitutive relations. Effective flow properties at the heterogeneous facies scale (m-scale) are determined by a steady state upscaling technique. Finally, the effective flow properties are implemented in a field scale (km-scale) simulation model. The simulation results show that the effective flow properties describe the reservoir WAG performance fairly accurately without any adjustment through history matching.
Problems of Ultra-Deep High-Temperature, High-Pressure Drilling
Authors: Shaughnessy John M. , Romo Louis A. , Soza Robert L. 
Published: December 2007

Abstract
Operators are looking at drilling for deeper gas reservoirs. There are a number of problems unique to ultra-deep drilling – greater than 20,000 feet. Well control is complicated by narrow margins and higher bottom hole pressures and temperatures. Application of tools that can assist in pore pressure prediction are limited by the depth, temperature and the high cost of errors. Well control problems can be spectacular. The depth pushes rig equipment loads to their design ratings. Maintenance, inspection and design of all components are more critical due to reduced margins. Wellbore tubulars are often designed for sour and corrosive production fluids. Those designs increase the pipe's weight and cause special handling requirements. Drilling tools are also limited by the depth, temperature and rock hardness. Two operators working in Texas, Louisiana and Wyoming drilling to depths of up to 25,000 feet have documented many of the industry's problems and current solutions. Understanding the problems and designing wells to reduce the risks is the first step to a cost effective drilling operation.
Improved Techniques to Alleviate Sustained Casing Pressure in a Mature Gulf of Mexico Field
Authors: Soter Kevin , Medine Felix , Wojtanowicz A. K. 
Published: December 2007

Abstract
The objective of this paper is to highlight the techniques used during a recent workover program to alleviate sustained casing pressure in a Gulf of Mexico field. Discussion will include cement and workover fluid programs, hole preparation before milling and cementing operations, and improved milling procedures.
The field was drilled during the 1980s and sustained casing pressure has been prevalent in some cases previous to initial completion operations. In two rig workover programs in 1989, and again in 1990, a total of nine temporary abandonments were attempted. These programs resulted in limited success until the most recent workover program beginning in 1999. In addition, a non-rig program was running concurrently with the most recent rig operations in an attempt to avoid rig intervention when possible. However, this system will not be discussed in this paper except as it applies to specific operations.
All indications are that the workover program was successful even though there was some need for remedial rig work on three wells while operations were ongoing. A review of past attempts, relying on internal correspondence and drilling reports, will be made and compared to the present 1999 rig operations program using first hand knowledge of the operations and decisions.
Continuous Rock Strength Measurements on Core and Neural Network Modeling Result in Significant Improvements in Log-Based Rock Strength Predictions Used to Optimize Completion Design and Improve Prediction of Sanding Potential and Wellbore Stability
Authors: Suárez-Rivera Roberto , Ostroff Gary , Tan KaiSoon , Begnaud Bill , Martin Wesley , Bermudez Tony 
Published: December 2007

Abstract
The scaling-up of laboratory rock mechanical measurements from sample-scale to reservoir-scale is fundamental to evaluation of wellbore stability, sanding potential, reservoir compaction or casing failure. Understanding rock heterogeneity is fundamental for adequate scaling-up laboratory measurements to core- and reservoir-scales and thus, to predictions of mechanical failure. Historically, scaling-up from core scale to reservoir scale has been dependent on calibration of log-based models to a sparsely sampled data set of rock mechanical property measurements made on core plugs. Such a sparsely sampled data set of core plug measurements alone may inadequately characterize the range heterogeneities in the reservoir, resulting in less than optimum log-based predictive models. With the introduction of continuous, high resolution, rock strength (UCS) measurements on core via scratch testing, an excellent calibration reference for producing robust log-based predictions of rock strength now exist.
In this study, high-resolution measurements of strength heterogeneity were obtained as a function of core length and were correlated with fundamental textural and compositional parameters from petrographic analysis. Using adaptive learning neural networks, fundamental relationships between log measurements and rock strength were obtained. This methodology was adequate for characterizing the intrinsic rock heterogeneity at appropriate scales for mechanical analysis of completion design and sanding (0.25 ft). The methodology is also potentially applicable to the scaling-up of other fundamental mechanical properties such as in-situ strength, compressibility and thick-walled cylinder strength.
Results show that intrinsic textural heterogeneity and strength heterogeneity are strongly related in sedimentary rocks. Recognizing the importance of rock heterogeneity and being able to scale-up this property to core and reservoir scales via log measurements results in significant improvements in the predictive capacity for sanding potential and wellbore stability. For example, thin layers of considerably weaker-strength than the surrounding rock, undetectable from conventional log-based rock strength predictions, were detected and included in the mechanical model. In addition to possessing high sanding potential, these weaker sections are also regions of fluid loss during drilling. Results can be used for selection of competent rock across the field (based on LWD measurements) for multilateral junction placement, and for selection of optimum completion strategies.
High-Temperature Wells with Lost-Circulation Demands and Reverse Circulation Placement Technique Using Foamed Cement Systems: Two Case Histories
Authors: Moore Robert , Bour Daniel L. , Reed Shawn , Hernandez Rafael 
Published: December 2007

Abstract
Drilling activities in diverse areas can pose significant challenges for conventional cement systems and circulation methods. To overcome these challenges, a unique cementing system and circulation method has been tested in the field with great success. This paper details how these technologies and techniques were successfully used in the cementation process of one casing string in a relatively shallow geothermal well in central California and a relatively deep string in central Wyoming.
Globally, a great many wells experience lost-circulation problems that require the reduction of circulation pressures to allow proper placement of cement to provide annular coverage. To help minimize these circulation pressures, cement was pumped into the annulus directly, significantly reducing placement pressures and allowing placement of the cement with no apparent losses—a process referred to as the reverse circulation placement technique (RCPT). In each of the deep and shallow applications discussed, the placement technique and the individual slurry designs address temperature issues.
Using Spectral Decomposition for Integration of Multi-Scale Data in High Resolution Reservoir Modeling
Authors: Gilbert Fabien , Andrieux Benoit 
Published: December 2007

Abstract
The spatial heterogeneity of rock properties within a hydrocarbon reservoir has a large effect on fluid flow. Reservoir heterogeneity can be described over a wide range of spatial scales. Each data source that is integrated into the geological model represents a specific scale of information. For example, well data generally provide finer-scale information than do seismic data. The proper integration of different data types into the geological model should account for their difference of scale. Recently, several geostatistical methods have been developed to account for variation in different scales of heterogeneity. Deficiencies in those methods include an inability to identify spatial components that have physical interpretations (factorial kriging), a difficulty in controlling model perturbations (sequential gaussian simulation with non stationary kriging or block cokriging). These deficiencies are particularly true when integrating seismic information into the geological model. In this context, we propose a methodology which allows integration of reservoir properties (known at wells, with high vertical resolution) and seismic attributes (laterally dense but with low vertical resolution) overcoming these deficiencies. Our methodology is based on a spectral decomposition of high resolution well information using spectral characteristics of seismic attributes. Different components are then simulated with seismic information as a constraint for the component which bandpass is consistent between well and seismic data. All components are then recombined and transformed to generate the desired reservoir property. This methodology is evaluated against others in terms of easiness of implementation, computing time, impact of the seismic data and similarity to a synthetic model. An application of this methodology to a real data set is presented. The geological environment of the reservoir is a mixed carbonate platform. Porosities are simulated at a fine scale constrained by a 3D impedance cube.