bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Design Method for Deepwater Surface Casings
Authors: Jeanjean Philippe 
Published: December 2007

Abstract
This paper presents a method to calculate the load bearing capacity of surface casings. The method clearly describes how to calculate the immediate capacity of the conductor and how to estimate the soil set-up with time. The recommended equations for set-up calculations are based on the results of three proof-load tests performed on partially set-up conductors. The paper also lists a series of key parameters that need to be controlled for a successful jetting operation. The overall method has been calibrated against 20 successful installation records.
Pore Pressure Prediction for the Cocuite Field, Veracruz Basin
Authors: Sayers Colin M. , Hooyman Patrick J. , Smirnov Nikolay , Fiume Giuseppe , Prince Antonio , de Leon Mojarro Jose C. , Romero Martin Terrazas , Gonzalez Oscar Marquez 
Published: December 2007

Abstract
Seismic velocities from a three-dimensional (3D) seismic survey over the Cocuite field in the Veracruz basin, Mexico, were used to predict pore pressure in order to optimize drilling operations in this area. The accuracy of the seismic velocities was assessed using a comparison with interval velocities calculated by upscaling sonic logs and by inverting time/depth pairs from check shots measured in wells in this area. To calibrate the velocity to pore pressure transform, available pressure tests and drilling mud weights were used to estimate formation pore pressure. This technique results in 3D models that are less uncertain and of higher density than conventional techniques, and that improve drilling safety and economics in overpressured areas.
Analysis of Black Oil PVT Reports Revisited
Authors: McCain William D. 
Published: December 2007

Abstract
Combinations of data from two laboratory procedures, differential liberation and separator test, are used to determine values of oil formation volume factors and solution gas-oil ratios for pressures below the bubblepoint pressure of the reservoir oil. The equation commonly used to calculate the solution gas -oil ratio is incorrect: the correct equation is derived. The equation used to calculate the oil formation volume factors is correct; however, a derivation illustrating the underlying assumptions has not been published. This derivation is also examined.
Ageing Facilities Present a Potential Environmental Threat
Authors: Sparks Ronald L. , Holliday George H. 
Published: December 2007

Abstract
Ageing Exploration and Production (E&P) facilities offer either a potential environmental threat or change. These potentials exist, if the property is retained or sold. This paper discusses the potential and sometimes real problems and/or benefits associated with holding or divesting of ageing producing properties. We have observed a number of old producing properties – some being retained, some being transferred from major producers to independent operators and more importantly, some being transferred from independent producers to minor operators. In either case, the original operator needs to evaluate the economics of elevating and maintaining the property to regulatory requirements prior to transfer. There is a real possibility the original owner must monitor the future operations of the divested lease to avoid future liability.
This paper provides insight into what circumstances place operators in jeopardy and how to evaluate the associated regulatory problems. Most papers discuss regulations from the programmatic aspect rather than a how-to-do aspect.
We concluded any potential buyer of an ageing producing property must either conduct or receive an environmental assessment of the potential for environmental problems. More importantly, the divesting operator must have confidence the purchaser will not devastate the lease or operate in an unsafe manner, leaving the remediation or liability to the previous or original owner. This is particularly true of the transfer from an independent operator to another independent operator. Further, there is need for the E&P industry to encourage the various Trade Associations to solicit regulatory protection after divestiture. The findings presented in the paper are based on personal observations of the authors.
Study of Vuggy Carbonates using X-Ray CT Scanner and NMR
Authors: Hidajat I. , Mohanty K. K. , Flaum M. , Hirasaki G. 
Published: December 2007

Abstract
Most existing permeability correlations for carbonates assume that vugs do not contribute to permeability. This may not always be the case, since vugs may be connected in some formations and contribute to the permeability. The objectives of this work are to identify vug connectivity by using X-ray CT scan and thin-section images of carbonates and to improve the NMR correlation for carbonates system. Six carbonate samples from Yates West Texas field were studied. Porosity and permeability of each sample were measured. The pore size distribution of these rocks is characterized by mercury porosimetry and NMR T2 measurements. Thin sections in the horizontal and vertical directions were prepared from the end pieces of the samples and were analyzed by using optical microscope. CT scanning of the core materials shows that porosity varies significantly along the core length. Some samples also show very distinct preferentially flow path, which affected the oil recovery. As revealed by the thin section analysis, the permeability of the samples studied is controlled either by the intergranular porosity or by the small channel that connects different vugs. The results of capillary pressure and NMR T2 measurement shows multimodal pore throat and pore body size distributions. The permeability is estimated by using effective medium approximation. All parameters used in effective medium approximation are derived from NMR T2 distribution by fitting with trimodal Weibull distribution. A better understanding of the contribution of vugs to permeability of carbonates is developed from this study.
Wettability, Saturation, and Viscosity Using the Magnetic Resonance Fluid Characterization Method and New Diffusion-Editing Pulse Sequences
Authors: Freedman R. , Heaton N. , Flaum M. , Hirasaki G. J. , Flaum C. , Hürlimann M. 
Published: December 2007

Abstract
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.
Testing Conventionally Untestable High-Flow-Rate Wells with a Dual Energy Venturi Flowmeter
Authors: Oyewole A. A 
Published: December 2007

Abstract
Evaluating the productivity of a well through well testing is an essential aspect of managing production operations and reservoir recovery. When the reliability of gas, oil, and water flow rates is challenged by common events such as flow rates beyond the separator capacity or oil-water emulsions, the value of the well test can be severely diminished or even negative. Action taken or not taken as a result of an erroneous well test result can be counter to the production objectives and costly to the reservoir recovery.
This paper documents the use of a mobile dual-energy multiphase venturi flowmeter to test high-pressure and high-flow-rate wells in an offshore Nigeria field. Problematic fluid properties and challenging separation conditions limited the capabilities of the test separators to adequately measure the flow rates of the individual phases of the well effluent. Reliable rate measurements were hindered by the well's high pressure and high flow rates and by the presence of oil-water emulsion, which made phase separation extremely difficult.
Examples of well tests performed with the flow meter demonstrate the benefits of robust measurement principles in these adverse conditions. The value of capturing the flow transients using a high-frequency dual-energy spectral gamma ray detector is also illustrated, as it allowed a better understanding of the behavior of fluid flow in the wellbore. The flowmeter data enabled production diagnostics. Based on the flowmeter information, recommendations to further investigate the sources of water entry into the wellbore were made.
Modeling of a Deepwater Turbidite Reservoir Conditional to Seismic Data Using Multiple-Point Geostatistics
Authors: Strebelle Sebastien , Payrazyan Karen , Caers Jef 
Published: December 2007

Abstract
Geological interpretation and seismic data analysis provide two complementary sources of information to model reservoir architecture. Seismic data affords the opportunity to identify geologic patterns and features at a resolution on the order of 10's of feet, while well logs and conceptual geologic models provide information at a resolution on the order of one foot. Both the large-scale distribution of geologic features and their internal fine-scale architecture influence reservoir performance. Development and application of modeling techniques that incorporate both large-scale information derived from seismic and fine-scale information derived from well logs, cores, and analog studies represents a significant opportunity to improve reservoir performance predictions.
In this paper we present a practical new geostatistical approach for solving this difficult data integration problem and apply it to an actual, prominent reservoir. Traditional geostatistics relies upon a variogram to describe geologic continuity. However, a variogram, which is a two-point measure of spatial variability, cannot describe realistic, curvilinear or geometrically complex patterns. Multiple-point geostatistics uses a training image instead of a variogram to account for geological information. The training image provides a conceptual description of the subsurface geological heterogeneity, containing possibly complex multiple-point patterns of geological heterogeneity. Multiple-point statistics simulation then consists of anchoring these patterns to well data and seismic-derived information. This work introduces a novel alternative approach to traditional Bayesian modeling to incorporate seismic.
The focus in this paper lies in demonstrating the practicality, flexibility and CPU-advantage of this new approach by applying it to an actual deep-water turbidite reservoir. Based on well log interpretation and a global geological understanding of the reservoir architecture, a training image depicting sinuous sand bodies is generated using a non-conditional object-based simulation algorithm. Disconnected sand bodies are interpreted from seismic amplitude data using a principal component cluster analysis technique. In addition, a map of local sand probabilities obtained from a principal component proximity transform of the same seismic is generated. Multiple-point geostatistics then simulates multiple realizations of channel bodies constrained to the local sand probabilities, partially interpreted sand bodies and well-log data. The CPU-time is comparable to traditional geostatistical methods.
Geostatistical Assignment of Reservoir Properties on Unstructured Grids
Authors: Deutsch C. V. , Tran T. T. , Pyrcz M. J. 
Published: December 2007

Abstract
Reservoir simulation is often performed on irregular nonCartesian grids. A common methodology for building the input reservoir models is to perform geostatistical reservoir models on a fine grid and then to average them to the coarser unstructured grid. This method is computationally expensive; a more efficient approach is to modify the geostatistical algorithms to directly populate the unstructured grid.
The required modifications are described in this paper. First, direct simulation must be used in place of the more common Gaussian simulation. This is required because reservoir properties do not average linearly after Gaussian transformation; averaging is required because each grid block potentially has a different volume. Second, volume averaged variogram or covariance values are required between two arbitrary blocks v1(u) and v2(u’). These must be calculated quickly and efficiently. Third, to maintain a reasonable speed of geostatistical simulation on unstructured grids a customized search and a non-stationary covariance lookup table of the average covariance between blocks is required. Finally, directional permeability requires a special transformation to account for the nature of averaging.
We present the implementation details and some results using tartan and radial grids.
Sensitivity Analysis of Petrophysical Properties Spatial Distributions, and Flow Performance Forecasts to Geostatistical Parameters Using Derivative Coefficients
Authors: Landa Jorge L. , Strebelle Sebastien 
Published: December 2007

Abstract
This paper presents a methodology to assess the relative impact of geostatistical parameters on reservoir property models and flow simulation results using sensitivity coefficients.
Petrophysical properties that are correlated cannot be simulated independently. To account for cross-correlation between properties such as porosity and permeability, common practice consists in using sequential workflows to construct reservoir models. Workflows are intricate combinations of geostatistical simulations and deterministic operations that proceed sequentially. The output of one particular step can serve as an input to several subsequent steps. Thus it is very difficult to determine which modeling parameters have the greatest impact on the final reservoir model. Yet, determining those most sensitive parameters is critical for the Earth scientist to better allocate his time and modeling efforts.
Such sensitivity analysis should be performed from both a static and a dynamic perspective. First, we want to identify the parameters that affect most the spatial distribution of the petrophysical properties. Each parameter, e.g. the direction of anisotropy of the porosity variogram or the mean of the porosity distribution, is perturbed independently. Resulting changes in porosity and permeability distributions are mapped and analyzed. The most sensitive parameters are retained. Their impact on individual well performance and whole field production is then evaluated using a modified reservoir simulator that allows computing sensitivity coefficients. Although some linear assumptions are used, the static and dynamic sensitivity derivatives appear to provide a very powerful guide to prioritize reservoir-modeling steps.
In this paper, we apply that methodology to an actual reservoir located offshore of Nigeria with 75 wells and more than 30 years of production history.
Openhole Gravel Packing — An Evolving Mainstay Deepwater Completion Method
Authors: Grigsby Tommy , Vitthal Sanjay 
Published: December 2007

Abstract
Operators have found that by integrating drilling and completion techniques, they can develop a highly reliable openhole horizontal gravel-pack completion that can control sand production and produce hydrocarbons at a high-rate. Because of the success of this methodology, it has become a mainstay completion technique in the deepwater developments in Brazil and has shown the same potential for upcoming deepwater developments in West Africa.
This paper will discuss the evolution of the integrated concepts, the "lessons learned" that are being used to increase the scope of application, and how new techniques are enhancing reliability for these completions. Specifics include advances that eliminate openhole tortuosity in openhole drilling techniques, new downhole tools that can reduce risk as well as completion cycle time, and improvements in gravel pack fluids.
These advances are continuing to push the technological envelope. The new technological benefits are: Reduced completion cycle time, thereby reducing completion costReduced formation damageImproved completion reliability throughout the potential life of the well.
An Integrated Experimental and Numerical Approach to Assess the Performance of Solvent Injection into Heavy Oil
Authors: Dauba C. , Quettier L. , Christensen J. , Le Goff C. , Cordelier P. 
Published: December 2007

Abstract
Injection of gaseous solvent in heavy oil reservoirs is considered as an alternative recovery technique to thermal processes. The feasibility and performance of this technique, although numerous issues remain, are assessed at the macroscopic scale through an integrated approach in four steps. This paper describes: The design of the optimum solvent composition: Thermodynamic simulations were carried out to obtain the composition of the relevant solvent, which must be gaseous and close to miscibility under reservoir conditions. The following composition was achieved: 80%C2 and 20% C3.The PVT analysis of both reservoir oil and several mixtures with injected solvent: Results of the PVT experiments carried out to characterize the multi-phase behavior, the evolution of viscosity and density versus the amount of injected solvent are presented. A Peng Robinson equation of state, tuned on one of the oil-solvent mixtures, predicts correctly the properties (Psat, GOR, density) of the other ones. On the other hand, the usual Lohrenz-Bray-Clark correlation underestimates the viscosity decrease of the saturated oil.The design of the long core experiment: the injection rate for a stable displacement is determined according to the conclusions of simulations performed both in 1D and 2D. Finely gridded 2D simulations are carried out to investigate the effect of small-scale heterogeneity and show some fingering of the diluted oil into the original heavy oil.The core flood experiment under reservoir conditions: Solvent is injected top-down into an unconsolidated 35-cm long core. New insights into recovery, oil and solvent produced rates, GOR and composition of produced oil versus time are reported. The saturation profiles monitored by 1D X-Ray source are consistent with a gas-drive stabilized by capillarity.
Conclusions about the main mechanisms involved in this solvent coreflood are presented; they should be confirmed by the history match of the experimental results.
Effects of Non-Darcy Flow on Pressure Transient Analysis of Hydraulically Fractured Gas Wells
Authors: Alvarez Cesar H. , Holditch Stephen A. , McVay Duane A. 
Published: December 2007

Abstract
Conventional well-testing techniques are commonly used to evaluate pressure transient tests of hydraulically fractured gas wells to estimate values such as formation permeability, fracture half-length, and fracture conductivity. When non-Darcy flow occurs along the fracture, analysis of the pressure transient test data using conventional analyses methods will produce incorrect values of fracture conductivity and fracture half-length.
This work emphasizes the importance of non-Darcy flow in the hydraulic fracture and its effects on pressure buildup analyses of hydraulically fractured gas wells. A reservoir simulator was used to generate pressure drawdown and buildup data both with and without the effects of non-Darcy flow. These synthetic buildup tests were then analyzed using conventional well-testing techniques. We found that when non-Darcy flow occurs along the fracture, the estimated fracture conductivity and fracture half-length represent only a small fraction of the actual values. Also, the degree to which the non-Darcy flow affects the well-test results depends upon the values of fracture permeability, water saturation inside the fracture, and the production rate during the drawdown period. If the incorrect fracture properties obtained from conventional analysis are used in reservoir simulation forecasting, critical values such as production rate and total recovery will be miscalculated.
Since conventional well-test analysis cannot be used to determine fracture parameters reliably, simulation history matching is the only appropriate method to correctly analyze buildup pressure response from hydraulically fractured wells in gas reservoirs.