bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wettability, Saturation, and Viscosity From NMR Measurements
Authors: Freedman R. , Heaton N. , Flaum M. , Hirasaki G. J. , Flaum C. , Hürlimann M. 
Published: December 2007

Summary
This paper discusses a new nuclear magnetic resonance (NMR) method that can provide wettability, saturation, and oil viscosity values in rocks partially saturated with oil and brine. The method takes advantage of two new technological advances in NMR well logging—the MRF* Magnetic Resonance Fluid Characterization Method and NMR "diffusion-editing" (DE) pulse sequences. We discuss the principles underlying the fluid characterization method and the pulse sequences. The fluid characterization method is used to provide robust inversions of DE data suites acquired on fully brine-saturated and partially saturated rock samples. The outputs of the inversion are separate diffusion-free brine and oil T2 distributions for the fluids measured in the rocks.
NMR measurements on partially saturated rocks are sensitive to wettability because of surface relaxation of the wetting-phase fluid. The surface relaxation rate, however, must be significant compared to the bulk relaxation rate in order for wettability to noticeably affect the NMR response. We present results showing that the surface relaxation rate at lower wetting-phase saturations is enhanced compared to that measured at higher saturations. The consequence of wetting-phase saturation on NMR-based wettability determination is discussed. Wettability affects the relaxation rates of both the wetting and nonwetting phases in partially saturated rocks. Surface relaxation of the wetting phase in a rock results in shorter relaxation times than would otherwise be observed for the bulk fluid. The nonwetting-phase fluid molecules do not come into contact with the pore surfaces, and therefore their relaxation rate in the rock is the same as in the bulk fluid.
We present accurate and robust computations of diffusion-free T2 relaxation time distributions for both the wetting and nonwetting phases in four rocks that include two sandstones and two dolomites. A DE data suite was acquired on each rock, measured in two different partial saturation states and also fully brine-saturated. Wettability is determined by comparing the oil and brine T2 relaxation-time distributions measured in the partially saturated rocks with the bulk oil T2 distribution and with the T2 distribution of the fully brine-saturated sample. The brine and oil T2 distributions are used to compute saturation and oil viscosity values.
A general discussion elucidating the sensitivity range and T2 limits of diffusion-based NMR methods is given in the appendix. The appendix also derives and displays the gain in signal-to-noise ratio that is achieved by using DE data sequences for fluid characterization in place of Carr-Purcell-Meiboom-Gill (CPMG) data suites.
Do Your Horizontal Wells Deliver Their Expected Rates?
Authors: Levitan M. M. , Clay P. L. , Gilchrist J. M. 
Published: December 2007

Summary
This paper presents the results of comprehensive analysis of BP horizontal-well productivity and completion performance data. The study was performed to benchmark the performance of existing horizontal wells with a view to developing simple, empirical techniques that could be used for predicting the performance of future wells. The developed correlation predicts a range of expected well productivities for future wells. This prediction reflects limitations in current completion technology and possible reservoir heterogeneities. The analysis method is based on presenting the existing well-productivity data in the form of dimensionless parameters—the well-productivity coefficient and the normalized productivity improvement factor (PIF). The results of this study can be used to:
Sense check the theoretical well-performance estimate for undeveloped discoveries with the historical performance for similar reservoirs. Provide quality control for newly commissioned wells to see if performance is as expected. Help optimize development well design (i.e., high-angle vs. conventional) for reservoir exploitation. Offer a means to rank well-surveillance work based on what the initial well performance is with respect to global historic experience.
Integrated Geological and Petrophysical Characterization of Permian Shallow-Water Dolostone
Authors: Holtz Mark H. , Major R. P. 
Published: December 2007

Summary
The complex interplay between depositional facies and diagenesis in dolostones makes calculating petrophysical properties from wireline logs challenging. Complex pore geometries and mineralogies control rock petrophysical properties. The complex mineralogy of some dolostone reservoirs, moreover, has profound effects on wireline-log measurements. Therefore, equations for calculating porosities and saturations must be tailored to specific pore-geometry/mineralogy combinations. If dolostone reservoirs are divided into petrophysical/mineralogical facies of similar depositional and diagenetic textures—and, thus, similar pore geometries and mineralogy—empirical equations that apply specifically to that geologically identified facies can be developed. These equations yield more accurate calculations of porosity and water saturation.
Our examples from Permian shallow-water dolostone reservoirs of the Permian Basin, southwestern United States, demonstrate analytical approaches for calculating petrophysical properties in these complex rocks. Four general petrophysical/mineralogical facies characterize Permian shallow-water dolostone reservoirs: (1) subtidal, mud-dominated dolostone; (2) subtidal, grain-dominated dolostone; (3) dolomitic and siliciclastic peritidal rocks; and (4) diagenetically altered, subtidal dolostone.
A Practical Method for Anticipating Asphaltene Problems
Authors: Wang J. X. , Buckley J. S. , Burke N. E. , Creek J. L. 
Published: December 2007

Summary
Asphaltenes can separate from some oils during depressurization. In other cases, the addition of lift or injection gas can destabilize asphaltenes. This paper presents an integrated approach to predicting all these potential asphaltene problems. Laboratory characterization of asphaltene stability in stock-tank-oil samples is used in combination with standard pressure/volume/temperature (PVT) and compositional data. Details of the characterization technique and prediction method are provided for problems of practical interest, especially for offshore developments where advance planning is of particular importance for many flow-assurance problems. Predictions of asphaltene stability with this approach are compared with live-oil measurements and field experience, where available.
Fluid Flow in Various Patterns and Implications for EOR Pilot Flooding
Authors: Brigham William E. 
Published: December 2007

Summary
Pilot testing of enhanced oil recovery (EOR) projects in the field is common, for such tests demonstrate the effectiveness of a particular EOR process. Nevertheless, separating the effects on recovery of pattern geometry, pattern size, and reservoir heterogeneities from the EOR process itself is nontrivial. This paper illustrates that geometric and geological factors are evaluated easily at unit mobility ratio. Subsequently, nonunit-mobility-ratio effects can then be predicted. In this fashion, the efficiency of the EOR process is decoupled from geometry and permeability variation.
Surface-Gravity Monitoring of the Gas Cap Water Injection Project, Prudhoe Bay, Alaska
Authors: Brady Jerry L. , Ferguson John F. , Seibert John E. , Chen Tianyou , Hare Jennifer L. , Aiken Carlos V. L. , Klopping Fred J. , Brown John M. 
Published: December 2007

Summary
Modeling and field-test surveys indicate that time-differenced surface gravity can be used to successfully monitor the Gas Cap Water Injection (GCWI) Project at Prudhoe Bay, Alaska. Simulation results have shown that more than 95% of the injected water can be accounted for, including reasonable assumptions concerning the noise level in the measurements. The flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft true vertical depth (TVD).
The world's first 4D surface-gravity surveillance of a water-flood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the approved Gas Cap Water Injection Project (GCWI) at Prudhoe Bay. A major factor in the approval of the waterflood was to show that water movement could be monitored economically with a very limited number of wells. Conventional monitoring techniques would have been cost-prohibitive because of the requirement for drilling numerous new surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be detected with high-resolution surface-gravity measurements. Field tests at Prudhoe Bay have demonstrated that sufficiently accurate gravity data can be obtained.
This paper will discuss both inverse modeling of time-differenced gravity maps and four test surveys that have been completed to perfect the gravity-measurement technique. Forward and inverse gravity modeling were carried out on a suite of reservoir simulations of the GCWI. Differences in the gravity field with time reflect changes in the reservoir densities, which in turn reflect pore-fluid content. A constrained least-squares method was used to invert synthetic gravity data for the subsurface density distribution. The modeling procedure has been formulated to allow testing for sensitivity to gravity-sampling patterns, noise, and various constraints on model parameters such as density, total mass, and moment of inertia.
These simulation results have shown that more than 95% of the injected water can be accounted for in the inverse model. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft TVD. Time-differenced surface-gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (−40°F) accurately enough to monitor the waterflood (gravity =±10 μGal and GPS = ±1 cm elevation; a μGal is approximately one-billionth of the Earth's normal gravity).
Uncertainty Assessment of Well-Placement Optimization
Authors: Güyagüler Baris , Horne Roland N. 
Published: December 2007

SummaryDetermining the best location for new wells is a complex problem that depends on reservoir and fluid properties, well and surface-equipment specifications, and economic criteria. Numerical simulation is often the most appropriate tool to evaluate the feasibility of well configurations. However, because the data used to establish numerical models have uncertainty, so do the model forecasts. The uncertainties in the model reflect themselves in the uncertainties of the outcomes of well-configuration decisions.We never possess the true and deterministic information about the reservoir, but we may have geostatistical realizations of the truth constructed from the information available. An approach that can translate the uncertainty in the data to uncertainty in the well-placement decision in terms of monetary value was developed in this study. The uncertainties associated with well placement were addressed within the utility-theory framework using numerical simulation as the evaluation tool. The methodology was evaluated by use of the Production forecasting with UNcertainty Quantification (PUNQ)-S3 model, which is a standard test case that was based on a real field. Experiments were carried out on 23 history-matched realizations, and a truth case was also available. The results were verified by comparison to exhaustive simulations. Utility theory not only offered the framework to quantify the influence of uncertainties in the reservoir description in terms of monetary value, but it also provided the tools to quantify the otherwise arbitrary notion of the risk attitude of the decision maker. A hybrid genetic algorithm (HGA) was used for optimization.In addition, a computationally cheaper alternative was also investigated. The well-placement problem was formulated as the optimization of a random function. The genetic algorithm (GA) was used as the optimization tool. Each time a well configuration was to be evaluated, a different realization of the reservoir properties was selected randomly from the set of realizations, all of which honored the geologic and dynamic data available from the reservoir. Numerical simulation was then carried out with this randomly selected realization to calculate the objective function value. This approach has the potential to incorporate the risk attitudes of the decision maker and was observed to be approximate but computationally feasible.
Analysis and Prediction of Microseismicity Induced by Hydraulic Fracturing
Authors: Warpinski N. R. , Wolhart S. L. , Wright C. A. 
Published: December 2007

SummaryThis paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Along with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid-saturated reservoirs experience much more widespread activity than do gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture, because considerable microseismic activity occurs around the tip as it propagates.
New Developments in Aerated Mud Hydraulics for Horizontal Well Drilling
Authors: Sunthankar A. A. , Miska S. , Kuru E. , Kamp A. 
Published: December 2007

SummaryDrilling using aerated muds offers a major advantage in controlling mud effective density, enabling both underbalanced and balanced drilling. However, planning of aerated mud drilling operations is difficult because of complex hydrodynamics of aerated mud flow, resulting in a lack of confidence in predicting and controlling operational variables. It is, therefore, necessary to better understand the hydraulics of aerated mud flows in order to be able to accurately calculate bottomhole pressure and optimal flow rates for drilling.Pressure losses are a strong function of gas-liquid flow patterns. The existing methods of predicting flow patterns are based on an extrapolation of results from pipe flow to flow in annuli. Therefore, to verify the applicability of this existing practice, the present study focuses on hydraulics of aerated fluids through a large-scale annulus.Extensive experiments were performed in a unique field-scale low-pressure flow loop (8×4.5 in., 90 feet long) in horizontal position with and without drillpipe rotation. The liquids used were water and aqueous polymer solution (CMC+XCD+water) at flow rates in the range of 75 to 360 gpm and air in the range of 10 to 1000 scfm. Measurements of pressure drop and average liquid holdup over the entire annular section were carried out. To our knowledge, no such data have been published before.It was observed that intermittent flow was present for most of the cases, which is contradictory to some existing field and simulation practices that assume homogeneous gas-liquid flow. Also, the flow pattern boundaries are shifted as compared to pipe flow, which necessitates the modification of flow transition criteria.Higher frictional pressure drop was observed in case of flow with drillpipe rotation. Also, a higher frictional pressure drop was found in case of air-non-Newtonian fluid flow as compared to air-water flow. The results of this study show that two-phase pipe flow models, when modified and applied to two-phase flow in annuli, considerably underpredict pressure drop occurring during the two-phase flow in annuli.
Use of Prior Information in Gradient-Based History Matching
Authors: Brun Bertrand , Barker John W. , Gosselin Olivier 
Published: December 2007

Summary
This paper demonstrates how certain geological constraints can be imposed during gradient-based history matching by use of a prior term in the objective function. We extend an existing method of parameter selection (gradzone analysis) to the case in which the prior covariance matrix is nondiagonal. We show that the parameter selection can be made independently of the weight assigned to the prior information, and illustrate how the shape of the gradzones is modified to reflect the correlation structure of the porosity or permeability fields. Finally, the use of the prior term to preserve a relationship between porosity and permeability during the historymatching process is demonstrated.
Permanent Fiber-Optic Monitoring at Northstar: Pressure/Temperature System and Data Overview
Authors: Kragas Tor K. , Turnbull Bill F. , Francis Michael J. 
Published: December 2007

Summary
In-well fiber-optic sensing systems offer the potential for continuous, highly accurate, highly reliable, real-time data measurements. During the past 3 years, permanent downhole fiber-optic pressure and temperature (P/T) transducers have become an accepted new technology in the oil and gas industry. Northstar, on the North Slope of Alaska, represents the first multiwell, new field development to incorporate fiber-optic P/T gauges. Real-time downhole pressure data are critical to managing the miscible-gas injection enhanced-recovery process at Northstar. Fiber-optic gauges were selected because of their reliability at high temperatures and their ability survive the severe shock and vibration conditions associated with post-installation perforating operations. As of publication, optical P/T gauges have been installed in 15 wells at North-star. The data have proved valuable to the asset team in monitoring the perforating program, determining initial reservoir pressure, managing well drawdown, diagnosing completion problems, building wellbore-hydraulics and inflow-performance models, and providing pressure-buildup data, all without the need for well interventions and the resulting loss in production volume.
Effect of Low Frequency Percussion in Drilling Hard Rock
Authors: Topanelian E. 
Published: December 2007

Introduction
In the development of a fluid-operated hammer drill for accelerated penetration of hard rock formations in oil wells, a research investigation was conducted to evaluate the percussion effects obtained with different design characteristics and to determine the possibilities of percussion in the low frequency range. Tests were conducted on granite blocks and comparable impact forces were measured with a load cell under selected test conditions. These full-scale laboratory tests provided an evaluation of the effectiveness of percussion which was further supported by actual downhole field performance.
While much pertinent data have been presented by other investigators the method of evaluation described in this article resulted in good correlation between laboratory and field performance and may be applicable in other low frequency percussion developments.

Experimental Method
For these tests the bit was held stationary and the test block was rotated and forced upward against the bit by a hydraulically-lifted rotary table. "Weight on bit" was calculated from pressure readings on the fluid system of the lifting cylinders-corrected for tare and friction. Percussion was obtained with several tubular hammers of different weights up to 320 lb. These were lifted mechanically and allowed to drop by gravity from various heights onto a slidably-mounted bit sub or "floating anvil" for calibration of the load cell response with known kinetic energy of the hammers. During evaluation of percussion effects, the hammers were hydraulically operated to provide a range of percussion frequencies up to 1,020 blows per minute delivered to the anvil.
To obtain comparable test readings, the load cell of the strain gauge type, was attached to the bottom of the anvil or bit sub in place of the bit. The load cell rested on a typical granite test block mounted on the drilling table. The latter was hydraulically supported as in the actual drilling operation. The effect of support resistance was the same for all tools when calibrating. Impact forces so determined were thus directly comparable with one another for the purposes of this investigation.
Combining Gradual Deformation and Upscaling Techniques for Direct Conditioning of Fine-Scale Reservoir Models to Interference Test Data
Authors: Mezghani Mokhlès , Roggero Frédéric 
Published: December 2007

Summary
Reconciling multiscale data for reservoir characterization is a crucial issue, because different data types provide different information about the reservoir architecture and heterogeneity. It is essential that reservoir models preserve small-scale property variations observed in well logs and core measurements and capture the large-scale structure and continuity observed in global measures such as well-test and production data.
In this paper, we present a new methodology to directly update fine-scale geostatistically-based reservoir models by combining gradual deformation parameterization for the fine-scale geostatistical model, and an upscaling technique for the coarse-scale flow simulation model. As consequence, both fine- and coarse-scale models are updated by dynamic data during the history matching process.
The proposed methodology includes:
Perturbation of the fine-scale geostatistical model using the gradual deformation parameterization. Gradual deformation ensures the preservation of the overall geostatistical properties of the fine model. Generation of the coarse-scale flow simulation model by upscaling the fine-scale geostatistical model. Fluid-flow simulation and sensitivity computation of the flow simulation results with respect to the fine-scale parameterization. This sensitivity computation is analytical and takes into account the upscaling process. Direct updating of the fine-scale geostatistical model using classical optimization process. Direct updating ensures consistency between the fine- and coarse-scale models.
The accuracy of the proposed methodology was improved by calibrating the flow simulation model. The objective of this calibration is to reduce the error introduced by the upscaling step during the flow simulation.
We applied successfully our methodology for fine-scale reservoir characterization process by integrating permanent downhole gauge measurements directly into a 3D-geostatistical model containing about two million gridblocks.
This test is designed to highlight several key issues of the proposed methodology:
Efficiency of the upscaling step, coupled with gradient-based optimization to speed up history matching. Usefulness of the calibration step for a correct integration of upscaling techniques in history matching. Capability of the methodology for maintaining consistency and coherency between fine-scale and coarse-scale models. Improvement of the reservoir characterization process by integrating dynamic data at both fine geostatistical scale and coarse simulation scale.
Buckling of Tubulars Inside Wellbores: A Review on Recent Theoretical and Experimental Works
Authors: Cunha J. C. 
Published: December 2007

SummaryThe buckling behavior of tubulars inside wellbores is the subject of many articles. This paper presents a general overview on most of the literature available on the subject and also comments on the different, and sometimes conflicting, solutions presented in various works.Different aspects of the phenomenon are discussed, including sinusoidal (lateral) and helical buckling and the influence of torque.