bluuebunny/crossref_metadata_2025_split huggingface dataset:
Outside Gravel-Pack Optimization, Based on Hydraulic Fractures Done in Gelatin
Authors: Stockhausen H. W. , Logan J. M. , Montgomery C. T. 
Published: December 2007

Abstract
This study use gelatin as an inexpensive physical model material to simulate poorly consolidated sediments and investigated selected problems associated with hydraulic fractures, in the sense of find ways to surround a vertical well with hydraulic fractures and extend selected ones into the formation as wing fractures in two different stress environments.
A technique was developed to control initial hydrofrac orientation based on tensile strength, fluid inertia, and breakdown pressure, which combine with an appropriate shooting phase oriented respect to the field stresses enable surround a well and form wing fractures to set an outside gravel pack.
The results of theses experiments were used to improve the novel technique of outside gravel pack as an economical alternative to enhance hydrocarbon productivity.
How Can Sand Production Yield a Several-Fold Increase in Productivity: Experimental and Field Data
Authors: Vaziri H. H. , Lemoine E. , Palmer I. D. , McLennan J. , Islam R. 
Published: December 2007

Abstract
Centrifuge physical model tests were performed to study the mode of failure during sand production and its concomitant impact on the productivity index. The tests simulated seepage-induced failure around a vertical well. Results indicate that in the presence of a competent cap rock (1) sand production results in the formation of a cone-shaped enlarged cavity; (2) surface subsidence of the reservoir due to loss of sand mass which may result in opening of flow channels under the cap rock; (3) for a given wellbore pressure, sand production ceases once the enlarged cavity lowers the flowrate to sub-critical level; (4) flow becomes diverted towards the upper perfs where the cavity radius is largest; (5) flow rate increase varies between 5 to 50 times depending on whether the mode and volume of sanding is sufficient to result in the formation of flow channels. The study performed shows that (1) the location of perfs affects the mode and magnitude of sand production and the concomitant productivity, and (2) long-term productivity can be improved through managed sand production. Presence of a competent cap rock is the key for maximizing the productivity via sanding. These findings are consistent with some field cases where extraordinary increases in production were noted as a result of sanding. Sand production, if properly managed, can reduce the completion costs (e.g., by omitting or delaying installation of sand exclusion measures) and improve the long term productivity by removing the skin damage and also through creating voids and zones of higher porosity around the well and under the caprock.
Real-Time Control of Low-Polymer Fracturing Fluids
Authors: Harris Phillip C. , Walters Harold 
Published: December 2007

Abstract
Productivity gains experienced with low-polymer-concentration fracturing fluids are real. When less polymer is injected into the formation, less polymer residue remains in the proppant pack to cause damage. The 15- to 25-lbm/Mgal polymer concentration fluids now being used have been optimized to produce viscosities similar to the 30- to 40-lbm/Mgal fracturing fluids of the previous generation.
Optimization is a laborious, but straightforward process with a traditional couette-type viscometer. Selected polymer-crosslinker combinations are tested to find the highest viscosity possible for the group as a function of preconditioning shear rate, temperature range, pH, ionic strength, gel stabilizer, gel breaker, surfactant, and proppant type. As each variable is optimized, its effect on the other variables must be examined to ensure the consistency of the data. If the data are consistent, mathematical modeling can be performed. Good computer models allow the practicing engineer to determine the chemical composition of a fluid required for producing a specific viscosity at a given time and temperature.
The second requirement for real-time control is knowledge of the fluid temperature in the wellbore and fracture as a function of the pumping schedule (i.e., rate, volume, distance, etc.). Computer design programs can generate a pumping schedule that is ramped between chemical and proppant stages, or at least to a much larger number than the three or four stages typically used for older-generation designs. For true real-time implementation, field-scale equipment must also be able to implement the pumping schedule seamlessly.
For well productivity, only chemicals required for the specific fluid segment should be pumped, without any excess. Pumping a truly optimized fluid means that the treatment is always on the edge of its performance capabilities. This paper will document the multiple effects of fluid composition on optimized viscosity, and quantify the effects on proppant transport for treatments performed at temperatures up to 300°F.
An Improved Steerable System: Working Principles, Modeling, and Testing
Authors: Gaynor Tom , Chen David C-K , Maranuk Chris , Pruitt Jack 
Published: December 2007

Abstract
A new steerable motor assembly has been designed that provides significant advantages over conventional steerable motor assemblies. The new system, SlickBore™, is comprised of a uniquely designed pin-down mud motor with a specially designed long-gauge PDC bit in a matched drilling system. By treating the bit and motor as a system, it has been possible to overcome the directional limitations previously experienced when long-gauge bits, or short-gauge bits with piggyback stabilization, were used in combination with conventional motors.
This paper describes the new system, its key working principles, and the drilling tests and computer modeling used to confirm the initial design concepts. The paper will also highlight selected field results from more than 100 runs made to date. The field results have not only proven the working principles but also demonstrated its advantages over the conventional steerable systems. The benefits include increased ROP, improved hole quality with less hole spiraling and thus less tortuosity, reduced vibration, lower torque and drag, better steerability, better hole cleaning, increased bit life, and improved PDM and MWD reliability.
The Scratch Test: An Attractive Technique for Determining Strength and Elastic Properties of Sedimentary Rocks
Authors: Schei G. , Fjær E. , Detournay E. , Kenter C. J. , Fuh G. F. , Zausa F. 
Published: December 2007

Abstract
The Scratch Test is a relatively new technique for determination of mechanical properties of rocks. In a Scratch Test, the surface of the rock is scratched at constant depth (typically less than 1 mm) by a sharp cutter, while the applied forces are being monitored. It is found that these forces are closely related to the mechanical properties of the rock. The Scratch Test thus represents a direct measure on the core material, and provides continuous coverage of data for the entire length of available core material.
The work reported here is a detailed study of the Scratch Test as a technique for determining strength and elastic properties of sedimentary rocks. The work is based on extensive laboratory testing of many sedimentary rocks with different mechanical properties. The results of the study show that parameters obtained in a Scratch Test, in particular the Specific Energy, correlate very well with the Uniaxial Compressive Strength (UCS). The accuracy of the Scratch Test for rock strength determination is seen to be at least comparable to the accuracy of the UCS Test, while the resolution is even better. It is also found that the Scratch Test may be used to determine the elastic modulus of rocks with good precision. The Scratch Test only requires access to a free surface of the rock. Hence, it may be run on most available core material. Provided that the core is in a reasonably good shape, no special preparation is required for the test, which is thus both quick and cheap. Unlike the UCS Test, the Scratch Test is almost non-destructive, and provides continuous data coverage. The Scratch Test is therefore a very attractive method for determination of stiffness and strength of core materials when addressing issues like reservoir compaction, hydraulic fracturing, borehole stability and sand production, offering a better resolution and data coverage than any other technique available today. Rock mechanical parameters derived from wire-line log data are continuous but have the disadvantage of being derived indirectly from other measurements, such as sonic velocity, density and porosity.
Determining the Effect of Geological and Geomechanical Parameters on Reservoir Stress path through Numerical Simulation
Authors: Khan M. , Teufel Lawrence W. , Zheng Ziqiong 
Published: December 2007

Abstract
Knowledge of the stress path (ratio of the change of effective horizontal stress to the change of effective vertical stress due to the reservoir pore pressure drawdown) that reservoir rock will follow during production and its effect on reservoir properties are critical for reservoir management decisions to maximize productivity. However, in-situ stress measurements needed to determine reservoir stress path are difficult and expensive to conduct, and the measurement may take several years to collect. In situ stress measurements in carbonate and clastic reservoirs indicate that the reservoir stress path is not isotropic loading (equal to 1.0) and can range from 0.14 to 0.761–2. In the laboratory usually reservoir stress path is calculated using uniaxial strain condition. The calculated uniaxial strain stress path can be significantly different from the measured stress path (Table 1).
This paper presents a finite element numerical model to predict the reservoir stress path due to the reservoir drawdown. The model incorporates essential geologic and geomechanical factors that may control reservoir stress path during production. The effect of size and geometry of the reservoir, contrasts in elastic properties between the reservoir and the bounding formations rock, transverse isotropy in elastic properties, plasticity, far-field boundary conditions, anisotropy in the reservoir initial stress states and stratigraphy and structure of the reservoir was studied. For isotropic reservoir properties, stress path becomes lower as the aspect ratio of length to thickness increase. Lenticular sandstone reservoirs have a higher stress path than blanket sandstone reservoirs that are continuous across the basin. Transverse isotropy with lower vertical elasticity than horizontal of reservoir rock increases the stress path, compared to isotropic conditions. Plasticity of the reservoir rock decreases the stress path significantly at the lower aspect ratio of reservoir, but increases with the increase of aspect ratio. However, plasticity of the bounding formations reverses the process.
Validation of the simulated results was done by simulating and matching the stress path of an existing reservoir. Reservoir initial conditions were obtained from published literature2 and considering that initial conditions simulated reservoir stress path was matched with the actual field measurements by adjusting the magnitude and orientation of the geological and geomechanical parameters.
A Three-Layer Modeling for Cuttings Transport with Coiled Tubing Horizontal Drilling
Authors: Cho Hyun , Shah Subhash N. , Osisanya Samuel O. 
Published: December 2007

AbstractA new approach of three-layer flow of two-phase (solid-liquid) fluid in annulus, i.e. a stationary bed of drilled cuttings at bottom; a moving bed layer above it; and a heterogeneous suspension layer at the top, is proposed to predict and interpret the cuttings transport mechanism. This new mathematical model is presented to overcome the limitation in the existing two-layer models. This enables efficient prediction of cuttings transport during horizontal drilling using coiled tubing. In particular, the model described in this paper formulates transport process and includes the relevant parameters such as rheological characteristics of the drilling fluid, cuttings size/sphericity/ concentration, wellbore geometry, eccentricity of the coiled tubing, and pumping rate of the drilling fluid.This paper presents the model development, solution, and simulation of the cutting transport process to illustrate the steps involved in determining the effect of each parameter during the drilling operation. Graphical charts and developed correlations between annular flow rate, rheology, wellbore geometry, eccentricity, cuttings size and concentration in each layer, and the carrying capacity are also presented. The simulation results show how to obtain a reasonable pumping velocity of drilling fluid with the possible lowest pressure gradient that might serve as an operational guideline during drilling. Furthermore, the effects of parameters affecting the efficiency of cutting transport are discussed. These results are compared with published experimental data. The observed agreement and discrepancies are discussed, and further improvements on the current model are proposed.
Maximizing Profitability in Reservoirs Using New Technologies For Continuous Downhole Pressure Systems
Authors: Buchwalter James L. , Calvert Ray E. , McKay Colin S. , Thompson Stephen J. 
Published: December 2007

Abstract
Continuous down hole data in conjunction with new reservoir analysis tools made to work with this data have the potential to revolutionize the accuracy of reservoir management. The economic value of continuous down hole pressure data and the array of available options justify the use of these systems in almost all petroleum reservoir developments. The greatest value of these gauges is that with new data analysis tools reservoirs can be accurately managed early in the producing life, thus optimizing both short and long term reservoir management strategies.
Traditionally, the value of these systems has been for completion optimization using a small subset of downhole data. The full value of the complete data stream has been ignored due to the large volumes of data, and the lack of software systems for efficiently working with these data. Consequently the reservoir has not been fully understood.
A system of software tools has been developed to capture the full value of the data from permanent down hole gauges. This new software system automates the filtering of these data in an intelligent fashion. The resulting filtered pressure data can then input into a variety of reservoir analysis tools, for example reservoir simulation programs can now have a continuous reservoir simulation. Reservoir and production engineers can always have the optimal production strategy for the reservoir based on the current data.
These tools are very easy to use, so models can be developed quickly and continually maintained with minimal effort.
Typically it takes less than a week to build the initial model, and only a few hours a month to update and maintain an accurate history match.
The paper will include a brief review of the down hole technologies and the software system which makes the data accessible to reservoir simulation and other reservoir analysis tools. Applications for the filtered data in both Gulf of Mexico and North Sea reservoirs will be introduced.
Geostatistical Inversion of 3D Seismic Data to Extrapolate Wireline Petrophysical Variables Laterally Away From the Well
Authors: Grijalba-Cuenca Alvaro , Torres-Verdín Carlos , van der Made Pieter 
Published: December 2007

Abstract
Interpretation of well-log data into petrophysical variables, such as effective porosity, permeability, and effective fluid saturation, provides an initial assessment of commercial hydrocarbon assets in the near vicinity of a well. A more accurate assessment requires quantitative indication of lateral continuity away from the well. Because wireline tools can only sense rock formation properties a few meters away from the well, assessment of lateral continuity is at best done qualitatively with the aid of stratigraphie analysis or well-to-well correlations. Seldom do these extrapolation methods take advantage of the nowadays commonly available 3D seismic data. In effect, despite possessing much less vertical resolution than well-log data, 3D seismic data have good lateral resolution that can naturally complement the vertical resolution of well-log data. We have developed an estimation procedure whereby wireline data can be extrapolated away from existing wells using geostatistical inversion of post-stack 3D seismic data. This procedure works by estimating a joint probability density function (PDF) that defines a physical relationship between seismic measurements (e.g. P-wave velocity, and P-wave acoustic impedance), and petrophysical variables (e.g. density/porosity and bed thickness) rendered by well-log data. The estimated joint PDF is further normalized to reflect a vertical resolution midway between the resolution of seismic data and the resolution of well-log data. Variograms are also estimated from well-log and seismic data that define the expected degree of lateral smoothness away from the well. We then generate stochastic realizations of petrophysical variables that not only honor the well-log data, but most importantly, that fully honor the 3D seismic data in a least-squares sense. In the presence of closely spaced wells, geostatistical inversion can also be used to estimate an accurate static reservoir model for the subsequent simulation and planning of in-fìll drilling and/or enhanced-oil-recovery operations. Examples are described in which geostatistical inversion provides lateral delineations of sand units consistent with measured fluid production data.
World Oil: Challenges and Opportunities
Authors: Safer Arnold E. 
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206
THIS PAPER IS SUBJECT TO CORRECTION
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Many observers are of the opinion that OPEC's dominance of the world oil market will last into the next decade. It is more likely, however, that economic forces will gradually re store a more equitable balance between producing and consuming nations and that the natural friction within OPEC itself will limit the cartel's power. U.S. international oil policy should recognize the likelihood of such a development.

Introduction
The purpose of this paper is to suggest an alternative point of view regarding the price of oil. The conventional wisdom today is that OPEC's near-monopoly control of the world's oil markets will last well into the 1980s, if not beyond. We challenge this point of view and suggest that a more probable outcome will be a gradual erosion of the cartel's position over the next few years. We do not foresee OPEC falling apart with earthshaking events of the sort that occurred when the cartel burst onto the world scene in late 1973 in the wake of war, an oil embargo, and quadrupled prices. Rather, we believe that natural economic forces will gradually work toward a reassertion of the market power of the oil-consuming nations between now power of the oil-consuming nations between now and 1980.
The policies devised by the U.S. and other Western governments to take advantage of this market shift will in large part determine the future viability of the cartel. Serious political considerations may suggest that the core Mideastern nations of OPEC may be vital to the security of the Free World, and that attempts to combat the cartel on purely economic grounds might well be contrary to our international political interests. While it is beyond the scope of this analysis to challenge that position on political grounds, we would suggest that the ability of the cartel to impose monopoly prices on the world's oil markets is an equally serious consideration on economic grounds.
The world has not really adapted to the price of international oil maintained by the strength of the oil cartel. The mounting international debt of many developing countries and of some industrialized nations is one important symptom of the disruptive nature of high oil prices. As long as large OPEC surpluses continue, there will be an ever-increasing burden of deficits in the oil-importing nations which must be financed through the international monetary system.
The Need for Dynamic Forecasting of Recoverable Reserves
Authors: Stout John L. 
Published: December 2007

THIS PAPER IS SUBJECT TO CORRECTION
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Estimates of hydrocarbon reserves have been in demand over the past thirty years. Examples follow to illustrate the necessity to try all approaches and effectively correct each prediction through use of newly acquired facts. All available details should be accurately compiled until calculated details are generated.
Methods of geologic basin analysis are discussed based on periodic re-evaluations of new field discoveries mad past performance of producing fields. Each basin's economic profile is determined by the rate of exploratory drilling and the ratio of remaining reserves to current production.
Although the U. S. to date has produced nearly one-third of the world's crude oil, our world economic position is being challenged more frequently and our ability to reliably forecast our remaining recoverable reserves assumes new importance with each challenge.

Introduction
Remaining hydrocarbon reserves in the U. S. are becoming increasingly important to the nation's economic and political future. A new pattern of exploration economics is now developing which indicates new drilling patterns and more efficient recovery. An increased price-cost ratio will immediately expand estimates of undiscovered recoverable resources and, at some threshold level recovery percentages for discovered petroleum will improve. Economists can readily see the effects of increased price-cost ratios that have developed since the 1973 embargo. The question now is "what will be the effect of the next world embargo?" The following statement by Frank G. Zarb outlining national objectives was read before a 1975 Senate hearing on "The Economic Impact of President Ford's Energy Program":