bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tuning of Computer Model Parameters in Managed-Pressure Drilling Applications Using an Unscented Kalman Filter Technique
Authors: Gravdal J. E. , Lorentzen R. J. , Fjelde K. K. , Vefring E. H. 
Published: December 2007

Abstract
In order to manage the annular pressure profile during Managed Pressure Drilling (MPD) operations, simulations performed with advanced computer models are needed. To obtain a high degree of accuracy in these simulations it is crucial that all parameters describing the system are as correct as possible. A new methodology for real time updating of key parameters in a well flow model by taking into account real time measurements, including measuring uncertainty, is presented. Key model parameters are tuned using a recently developed estimation technique based on the traditional Kalman Filter.
The presented methodology leads to a more accurate prediction of well flow scenarios. Although the present study is motivated by applications in MPD, the idea of tuning model parameters should be of great importance in a wide area of applications.
The performance of the filter is studied, both using synthetic data and real measurements from a North Sea High-Pressure-High-Temperature (HPHT) drilling operation. Benefits by this approach are seen by more accurate downhole pressure predictions which are of major importance for safety and economic reasons during MPD operations.
Deep Directional Electromagnetic Measurements for Optimal Well Placement
Authors: Omeragic D. , Li Q. , Chou L. , Yang L. , Duong K. , Smits J. , Lau T. , Liu C. B. , Dworak R. , Dreuillault V. , Yang J. , Ye H. 
Published: December 2007

Abstract
A new logging-while-drilling (LWD) tool that incorporates directional antennae and long measurement spacings has been developed and field tested. The directional electromagnetic (EM) tool measurements are more sensitive to approaching resistivity boundaries than existing propagation resistivity tools. Combining measurements from symmetrically arranged pairs of antennae further amplify this boundary effect while minimizing undesirable sensitivity to dip and anisotropy. Novel data processing and structure visualization software was developed to aid the decision-making and planning process. Field test results from Oman and the North Sea illustrate how the directional EM measurements fulfill the requirements for geosteering in thin, dipping, and curving targets with lateral resistivity variations. In addition, the directional EM tool also enables improved characterization of resistivity and resistivity anisotropy in high-angle and horizontal wells.
A Timestepping Scheme for Coupled Reservoir Flow and Geomechanics on Nonmatching Grids
Authors: Gai X. , Sun S. , Wheeler M. F. , Klie H. 
Published: December 2007

Abstract
This paper presents numerical techniques for coupled simulations with different time scales and space discretizations for reservoir flow and geomechanics. We use an explicitly coupled approach together with an iterative coupling to increase stability and reduce time discretization error. An error indicator is proposed to determine when displacement must be updated and whether the explicit or iterative coupling technique is required. Under this setting, one geomechanics calculation is performed for several reservoir flow steps. For time steps without geomechanics updates linear extrapolated pore volume is used for porous flow calculations. The resulting algorithm is computationally more efficient than the iterative coupling, and it is more stable and accurate than the loosely coupled technique.
In the event that different meshes are used for the reservoir flow and geomechanics models, special treatments are required for the integration of the coupling terms over each element. To avoid complex 3D grid intersection calculations we propose to divide an element into a number of subelements and apply the midpoint integration rule over each subelement. Numerical results are presented to demonstrate the efficiency and accuracy of the proposed method for coupled simulations with different time and space discretizations.
Permanent Microseismic Monitoring System in a Long Horizontal Well
Authors: Rod M. H. , Zyweck M. , Dorn-Lopez D. W. , Frederiksen C. H. , Gaucher E. 
Published: December 2007

Abstract
A permanent microseismic monitoring array has been installed in a horizontal well with the objective of imaging propagation of acid fractures and water injection fractures in offset wells. The array consists of 16 geophones placed at 500 ft intervals along the horizontal section of a producing well, deployed inside the pre-perforated liner and coupled to the formation by gravity. Optimal monitoring conditions are achieved when production from the well is closed in, however, many events have been detected whilst the well is producing by applying a production noise filter. Microseismic events are detected, one per week on average, when the monitoring well is producing and 1-2 events per day when the well is shut in.
The microseismic monitoring well is located in the Halfdan field in the Danish North Sea. This chalk reservoir has been developed with a line drive waterflood configuration, alternating oil production and water injection wells. Parallel horizontal producers and injectors are drilled in the direction of maximum horizontal stress, 600 ft apart with reservoir completions in the range 10,000–15,000 ft. The relatively close well spacing is necessary to maximise recovery from the tight chalk reservoir. Multiple acid fractures are placed in producing wells to maximize productivity while fractures are induced by water injection in injection wells in order to achieve voidage replacement. Orientation of induced fractures along the direction of the horizontal wellbore is critical to avoid early water breakthrough and inefficient sweep patterns.
Approximately 450 microseismic events have been located from a total of 13 acid fracture stimulation treatments in two offset producers, both 1,200 ft from the monitoring well. Definitive fracture orientations have been determined for 8 acid fracture stimulation treatments. Contrary to expectations, the fractures have propagated orthogonally to the wellbore. This has resulted in a modification in the completion methodology for subsequent Halfdan producer wells. Water injection fractures have not been imaged with the microseismic network.
The Impact of Proppant Retardation on Propped Fracture Lengths
Authors: Gadde P. B. , Sharma M. M. 
Published: December 2007

Abstract
A model for the velocity of proppant particles in slot flow is presented. The proppant is either retarded or accelerated relative to the fluid depending on the ratio of the proppant size to the fracture width. It has been found that when this ratio is small, the proppant travels faster than the average fluid velocity at that location because the proppant tends to be confined to the center of the flow channel where the fluid velocity is higher. As the proppant size increases, the effect of the fracture walls becomes more important and the proppant is retarded by the walls. The retardation of particle relative to the fluid is greater for larger particles and greater proximities to the fracture walls due to the hydrodynamic stress exerted on the sphere by the walls in the narrow gap. A higher proppant concentration restricts the area available to flow and increases the drag forces on the particles.
A model is presented for the effect of fracture walls and proppant concentration on proppant transport. The effect of this increased drag force is accounted for by modifying the wall - particle interaction. The influence of the surrounding proppant spheres on the drag force on a particle is estimated from the effect of a wall on the drag force acting on a single particle. The equivalent hydraulic diameter is then used to determine the proppant retardation. The effects of wall roughness and fluid leakoff are discussed. Models are suggested that capture these first order effects.
The new model for proppant retardation has been incorporated into a 3D fracture simulator. Results show that the proppant placement is substantially different when proppant retardation/acceleration is considered. Comparisons of propped fracture lengths obtained with the new model agree much better with propped and effective fracture lengths reported in the field.
Efficient Delivery of Bolivian Exploration Well Despite Geological Uncertainty Using an Expert Bit-Selection System
Authors: Balda C. , Pacione M. , Evans H. 
Published: December 2007

Abstract
This paper will discuss the benefits of using an Expert Bit Selection (EBS) system for bit selection and estimated Rate of Penetration (eROP) modeling in the pre-drill, implementation and post well analysis phases of an optimization project for exploratory drilling in the Southwest Basin of Bolivia.
Drilling a vertical wildcat well in the SW Basin thrust belt presented a number of distinctive challenges. To reduce the associated risks, engineers consulted with local geological experts and produced multiple stratigraphic scenarios and likely formation top depths. These scenarios were modeled through regional correlation between offset formations and formation tops. The models were populated with anticipated operating parameters and used in the expert system to make bit selections appropriate for the specific drilling environment.
Constant monitoring of drilling data, cuttings descriptions and comparison of penetration rate with eROP while drilling ensured that the most representative scenario would be identified and appropriate bit recommendations prepared while tripping out of the hole. Additional changes to the EBS system model were made when unexpected lithologies were encountered and sequencing of formations varied significantly from the initial prognoses.
Despite encountering dramatically different formation types and tops from those prognosed, the EBS system helped save the operator 15 days relative to AFE and the 17-½" section (including running the 13-3/8" casing to bottom) was completed without incident. Additionally the number of bits used was 13 – 34 less than used on comparable wells.
Using an alternative analysis, by isolating flat times, the normalized time curve versus AFE showed a 27-day saving for the 17-½" section, which at an average rig cost of US$50,000/day translates into a saving of US$1.35 million.
Evaluation of Inflow Profiles Behind Tubing Using Pulsed Neutron Logs
Authors: Poe B. D. , Butsch R. J. 
Published: December 2007

Abstract
This paper presents the development of a production logging analysis methodology and associated formation inflow interpretation model for wells that may have their production tubing string setting depth below the top of at least the shallowest completed interval in the well. The practice of selecting a tubing setting depth greater than that of the shallowest completed interval in a well is often utilized in wells that produce significant amounts of formation liquids. The tubing string is set lower in the wellbore than the uppermost completed interval in order to assist in liquid unloading of the well.
Conventional production logging tools that utilize fluid velocity measurement devices such as spinners can not be used to measure the wellbore fluid velocities in the annulus of the casing and tubing strings in the well. As a result, the inflow profile of the completed intervals in the well that are shallower than the tubing string setting depth in the well (or in practice, somewhat even lower than the end of the tubing string due to convergence effects) can not be obtained with those devices without first raising the tubing above all of the completed intervals in the well. This repositioning of the tubing string setting depth so that a conventional production log can be obtained for those completed intervals can alter the inflow profile of the well.
In this paper, the description of a mathematical interpretation model that has been developed for reliably estimating the inflow profile of a well in which the production tubing string in the well extends to a well depth greater than the depth to the top of the shallowest completed interval in the well is presented. The production performance evaluation model described in this paper provides a means of determining the inflow behavior of a well of this type, without the need for repositioning of the tubing string so that it is set above all of the completed intervals in the well. The results of this analysis therefore are analogous and equivalent to that which would be obtained with conventional production logging methods if those inflow profile evaluation techniques could be used in wells of this type without repositioning of the tubing string. The wellbore flow measurements that are utilized in this production logging analysis are obtained with Pulsed Neutron logs and are the liquid holdup in the wellbore and the annular or tubular flow liquid velocities. The liquid holdup in multiphase flow in the well is determined using the Inelastic Ratio measurements of a Pulsed Neutron logging device and the annular flow water velocities are directly obtained from the analysis of water flow measurements in the well.
Fluid Flow and Particle Transport Analyses Show Minimal Effect of Annulus Between Horizontal Wellbore and Expandable Screen
Authors: Li J. , Hamid S. , Hailey T. , Simonds R. 
Published: December 2007

Proposal
Expandable screens are becoming increasingly more important in sand-control completions because of their exceptional capabilities for providing wellbore support and optimized wellbore geometry. This is particularly important for offshore horizontal wells. Currently, two types of screen expansion technologies exist; i.e., the constant-diameter (fixed-cone) expansion technology and the variable expansion technology. Each approach has its own advantages and disadvantages in terms of deployment, wellbore support, and inflow performance characteristics.
With fixed-cone expansion technology, the industry has had the concern that annular flows between the open hole and screen can lead to transport of formation sands. This phenomenon can lead to localized screen erosion due to partial screen blockage, concentrated flow in unblocked portions of the screen, and finally, failure of the filtration layers. This paper discusses a method that can determine the probability of the above concerns with a model that analyzes fluid flow and particle transport. The forces acting on individual sand particles are modeled to ascertain the particle transport within the annulus and determine annular flow problems. Based on a given production profile that takes into account the frictional pressure losses of fluid in the annulus and in the base pipe, this model can predict if there is any possibility that particles in the annulus will be transported. Using this method, the wellbore (annulus) section in which no particles would be transported can be predicted.
Computational Fluid Dynamic (CFD) simulations were carried out to study the flow distribution in the horizontal wellbore. At a given wellbore location, the percentages of fluid flowing inside the basepipe and in the annulus were calculated. The simulations typically showed that the average fluid velocity in the annulus is an order of magnitude less than the fluid velocity inside the base pipe. The study also showed that if designed properly, a screen with fixed-cone expansion can be used successfully without concern of particle transport and with very limited flow in the annulus.
Single Cutter Impact Tests Investigate Deep-Well Hammer-Drilling Performance
Authors: Green S. , Judzis A. , Curry D. , Black A. , Prasad U. , Rogers J. 
Published: December 2007

Abstract
The use of a percussion hammer can provide high penetration rates through hard rocks when air drilling. The work of this paper was partly sponsored by the US Department of Energy to develop hammer drilling techniques for drilling deep hard rocks, using real drilling muds. Unfortunately, development is complicated because understanding rock breakage and cuttings removal under the dynamic loading conditions of hammer drilling is difficult. Historically, empirical relations have been used to relate hammer blow energy and blow rate with drilling.
This paper presents results of carefully measured single cutter impact—as well as high rate and ‘static’—rock indentation tests under high borehole pressure conditions, using real drilling muds. The results include cutter force-displacement and crater volumes for both first stress wave (initial impact) and long time (quasi static) rock indentations. From this, specific energy for rock breakage (i.e. the energy to excavate a unit volume of rock) can be calculated.
The specific energy values measured in these single cutter impact tests show the rock destruction efficiency that can be achieved by impact loading. They are compared with specific energies measured during full scale hammer and rotary drilling experiments, under relatively similar conditions.
For a given rock type, impact stress, cutter configuration, wellbore pressure, and mud type are shown to be critical parameters. A key observation is that most of the rock breakage occurs during the first stress-wave, and for higher impact stresses above the dynamic confined indentation strength, relatively little additional rock breakage seems to occur.
Surfactant Gel Foam/Emulsion: History and Field Application in Western Canadian Sedimentary Basin
Authors: Gupta D. V. S. , Leshchyshyn T. T. , Hlidek B. T. 
Published: December 2007

Abstract
Surfactant gels were introduced into the Western Canadian Sedimentary Basin (WCSB) as fracturing fluids in 1998. These fluids proved to be successful for propped fracture stimulations in shallow gas wells. About the same time, it was found that surfactant gels could be foamed with nitrogen or emulsified with a high quality (volume fraction) of liquid CO2. Since their inception in the Canadian market, surfactant gel foams/emulsions have been used in coal-bed methane (CBM) and also in the stimulation of deeper, higher temperature applications.
This paper will discuss the use of these fluids in the WCSB as well as the chemistry of the fluids, laboratory conductivity measurements which show proppant pack retained conductivities of greater than 96%, and their application in more than 3,100 oil and gas producing zones. The fluids have been used in a variety of formations and in wells with permeability's from 0.1 millidarcies to 10 Darcies, depths in excess of 3000 m (10000 feet) and bottom-hole temperatures up to 100 °C (212 °F). For water-sensitive formations, foamed surfactant gel fracturing costs are significantly less in comparison to hydrocarbon, CO2, or methanol-based fluids.
Integrating Intelligent-Well Systems Into Sandface Completions for Reservoir Control in Brazilian Subsea Well
Authors: Moreira O. M. , Stacey A. , Anderson A. 
Published: December 2007

Abstract
The ability to integrate intelligent well systems into sandface completions is gaining importance as a critical success factor to economic development of smaller, subsea assets. For these types of assets to be economically viable, multiple zones must be tied together with fewer wells. To optimize production, the zones are often completed and commingled initially, then isolated to eliminate water or gas breakthrough. In many areas, such as the Campos Basin of Brazil where hydrocarbon-producing formations also have a tendency to produce sand, active sand control is also necessary. This paper describes the successful integration of an intelligent completion system into the sandface completion of a subsea well in the Bicudo field offshore Brazil. The well required mechanical isolation of two open-hole gravel packed zones to facilitate flow control. The operator also wanted to eliminate future workovers and use remote control to isolate the lower zone to prevent water breakthrough. Using external casing packers, removable production packers and an intelligent completion system with an advanced, hydraulically activated remote-control sliding sleeve, the resulting shallow-water, horizontal, subsea intelligent completion yielded double the expected recovery rates from the longest horizontal section ever completed by Petrobras.
A Fully Implicit, Parallel, Compositional Chemical Flooding Simulator
Authors: Han C. , Delshad M. , Sepehrnoori K. , Pope G. A. 
Published: December 2007

Abstract
We have developed a fully implicit, parallel, compositional reservoir simulator that includes both a cubic equation of state model for the hydrocarbon phase behavior and Hand's rule for the surfactant/oil/brine phase behavior. The aqueous species in the chemical model include surfactant, polymer, and salt. The physical property models include surfactant/oil/brine phase behavior, interfacial tension, viscosity, adsorption, and relative permeability as a function of trapping number. The fully implicit simulation results were validated by comparison with results from our IMPEC chemical flooding simulator (UTCHEM). The results indicate that the simulator scales well using clusters of workstations. Also, simulation results from parallel runs are almost identical to those using a single processor. Field-scale, high-resolution surfactant/polymer flood simulations were successfully performed with over 1,000,000 gridblocks using more than 100 processors.
Integrated Interpretation of a Rich Data Set From a New-Generation LWD Tool
Authors: Neville T. J. , Faivre O. , Sun H. T. , Weller G. 
Published: December 2007

Abstract
A new logging-while-drilling (LWD) tool combining traditional measurements of gamma ray, propagation resistivity, gamma-gamma density, and thermal-neutron porosity with measurements unique to the LWD arena opens up new opportunities for formation evaluation on LWD. Neutron capture spectroscopy provides elemental concentrations of major rock-forming elements; these can be translated into mineralogy and matrix properties such as matrix density and matrix capture cross section using well-established algorithms.
The combination of continuous matrix properties from neutron capture spectroscopy with conventional gammagamma density and enhanced thermal-neutron porosity measurements, and a new capture cross section measurement provide the means to calculate porosity and saturation directly from nuclear measurements. The use of this multiplicity of direct measurements allows for the calculation of accurate porosity and fluid saturations with reduced uncertainty and subjectivity when compared to traditional triple-combo interpretation.
The accurate clay fraction derived from neutron capture spectroscopy also allows for enhanced interpretation of saturation from resistivity in shaly sands. The availability of two independent saturation estimates from similar volumes of the formation allows for improved confidence in the water saturations obtained.