bluuebunny/crossref_metadata_2025_split huggingface dataset:
Role of Fracture Flow in Matrix-Fracture Transfer
Authors: Gautam P. S. , Mohanty K. K. 
Published: December 2007

Abstract
Although a lot of research has been done in modeling the oil recovery from fractured reservoirs by countercurrent imbibition, less attention has been paid in the past to the effect of the fracture fluid velocity upon the rate of oil recovery. Assuming oil saturation continuity at the matrix-fracture interface, we propose a droplet detachment model to arrive at an effective water saturation in a thin boundary layer at the matrix-fracture interface. This effective boundary water saturation is a function of fluid type, fluid velocity in the fracture and fracture geometry. For a highly water-wet reservoir, this model predicts that the increase in fracture fluid velocity would result in a higher boundary water saturation a matrix is exposed to, which in turn would increase the oil recovery rate from the matrix. It also predicts that the oil recovery rate does not scale linearly with the boundary water saturation. It also implies existence of an optimum fluid velocity through the fracture of a known geometry that maximizes oil/water ratio. The model predictions are compared with preliminary experimental results.
Pressure-Pressure Convolution Analysis of Multiprobe and Packer-Probe Wireline Formation Tester Data
Authors: Onur M. , Hegeman P. S. , Kuchuk F. J. 
Published: December 2007

AbstractIn cases where flow rate data are not reliable, the need for flow rate in estimating permeability from wireline formation tester multiprobe and packer-probe pressure data sets can be eliminated by the use of the so-called pressure-pressure (p-p) convolution. The p-p convolution is based on the use of two different pressure data sets recorded at different spatial locations and, thus, enables one to perform parameter estimation without flow rate. In this work, we present a detailed analysis of multiprobe and packer-probe pressure transient tests by considering various p-p convolution options. Both single layer and multilayer (crossflow) systems are considered. Approximate equations that apply during spherical and radial flow for a vertical well in a single layer system for various p-p convolution options are derived. These equations indicate which parameters can be uniquely determined from p-p convolution. It is shown that p-p convolution analysis can sometimes provide nonunique parameter estimates. Also, we provide a flow rate extraction method that proves useful to check the validity of parameter estimates obtained from p-p convolution analysis. Two example tests, a synthetic multiprobe test and a field packer-probe test, are provided to illustrate the methodology and procedures developed in this work.
Light Annular MudCap Drilling - A Well Control Technique for Naturally Fractured Formations
Authors: Colbert John W. , Medley George 
Published: December 2007

AbstractLight Annular MudCap drilling (LAMCD) is a safecost effective drilling technique that may be used to drill through massively fractured formations or where Karsts are prevalent, especially when productive fluids are sour. It is an adaptation to regular Mud Cap Drilling (MCD), used to drill formations such as the Austin Chalk. The technique was first developed and used in the Cogollo formation in South America and has recently been used to drill sour formations in Kazakhstan. The LAMCD technique allows the driller to control and monitor the amount of sour gas migrating into the annulus.Drilling through formations containing multiple large fractures using conventional well control techniques is impossible unless the fractures are sealed. In many cases where extremely large fractures or karsts (vugs/caverns) have been encountered, lost circulation technology has proven to be unsuccessful.1-7 If the fractured formation being drilled is a pay interval, plugging the fractures is counter-productive.The LAMCD well control/lost circulation technique entails drilling with the choke completely closed while using a rotating control device (RCD) to seal the annulus. A sacrificial fluid, usually fresh or brine water is injected down the drill pipe. The drilled cuttings are transported and deposited into the fractures or vugs. The annulus is periodically injected with a viscous fluid that has a density slightly less than the pore pressure equivalent, hence the name "Light Annular MudCap". This controlled displacement process results in a predictive positive casing pressure. The casing pressure will increase as hydrocarbons migrate up the annulus. The value of the casing pressure qualitatively corresponds to the height of the hydrocarbon migration. Once a predetermined casing pressure/height is reached, LAMC fluid is pumped into the annulus until all the hydrocarbon is displaced back into the formation. After all the hydrocarbons are purged from the wellbore, the casing pressure will return to a constant and predictable value.LAMCD is a well control/lost circulation technique that allows drilling through massive lost circulation zones without downtime associated with lost circulation and conventional well control. Penetration rates are increased significantly as well.This paper describes the application of Light Annular MudCap Drilling as well as the details of the method. Well control and equipment issues are addressed. Simple equations for estimating pressure and volume requirements during LAMCD are presented.
A New Skin Factor Model for Perforated Horizontal Wells
Authors: Furui K. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
Using a combination of analytical calculations and 3D finite element simulation, we have developed a comprehensive skin factor model for perforated horizontal wells. In this paper, we present the mathematical model development, and validation of the model by comparison with finite element simulation results. With the new perforation skin model, we then show how to optimize horizontal well perforating to maximize well productivity.
A cased, perforated well may have lower productivity (as characterized by a positive skin factor) relative to the equivalent openhole completion because of two factors – the convergence of the flow to the perforations and the blockage of the flow by the wellbore itself. Because of the orientation of a horizontal well relative to the anisotropic permeability field, perforation skin models for vertical wells that consider these effects, notably the Karakas and Tariq model1, are not directly applicable to perforated horizontal completions. Using appropriate variable transformations, we derived a skin factor model for a horizontal perforated completion that is analogous to the Karakas and Tariq vertical well model. The empirical parameters in the model were determined from an extensive 3D finite element simulation study.
The results of the new model show that the azimuth of a perforation (the angle between the perforation tunnel and the maximum permeability direction, usually thought to be the horizontal direction) affects the performance of perforated completions in anisotropic reservoirs. When perforations are normal to the maximum permeability direction, perforations will enhance horizontal well flow compared with an openhole completion (a negative skin factor). But if perforations are in the same direction as the maximum permeability, significant positive skin will result. The new skin factor model provides a clear guide to the shot density, perforation orientation, and level of perforation damage that is tolerable to create high productivity perforated completions in horizontal wells.
Chelating Agent-Based Fluids for Optimal Stimulation of High-Temperature Wells
Authors: Ali A. Husen A. , Frenier W. W. , Xiao Z. , Ziauddin M. 
Published: December 2007

Abstract
Chelating agents have the ability to complex and sequester many types of metal ions in aqueous solutions. These chemicals have been used extensively in oil and gasfield treatments for stabilization of iron, scale removal, and as stimulation agents. Examples of chelating agents are ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and nitrilotriacetic acid. In this paper we describe results from laboratory tests and field treatments using chelating agent-based fluids for matrix stimulation of high-temperature sandstone and carbonate formations.
In carbonates we have proven that formulations containing both EDTA and HEDTA will form wormholes at temperatures up to 400°F (204°C). Pioneering work in the late 1990s can be correlated with many of the results, but low-pH formulations of hydroxy chelating agents have unique characteristics that are especially suitable for stimulation of high-temperature carbonates. When tested in the lab at practical injection rates for field applications, chelating agent-based fluids were much more efficient than both mineral and organic acids. Formulations with very low corrosion rates on carbon steel and corrosion resistant alloys (CRAs) were developed for temperatures up to 425°F (218°C).
In sandstones we show that alkaline formulations containing surfactants and hydrotropes are more effective than mineral and organic acids for stimulating formations that are damaged with carbonates and acid-sensitive clays. Laboratory tests to optimize these formulations and field applications in deep, hot gas wells are presented. A gas well in a sandstone formation with a bottomhole static temperature (BHST) of 300°F (149°C) was stimulated with a noncorrosive chelating agent formulation. The well had produced &gt;2 MMscf/D gas while it was completely plugged prior to the chelant formulation treatment.
Natural Gas: The Excruciating Transition
Authors: Oligney R. E. , Economides M. J. 
Published: December 2007

Abstract
Natural gas has gone through an unprecedented roller coaster in 2000 and 2001 which among other things included the collapse of Enron, one of the biggest players in the field. Prices rocketed from $2 to over $10 and then declined to below $3 per Mscf. Yet, fluctuations notwithstanding, the "new" natural gas price is $3.00 to $3.50, both floor and ceiling. The floor, calculated by us, is set by full-cycle costs, which include potential reserves, discovery rates, proved reserves, the activation index by region and well decline rates. The price ceiling is set by liquid natural gas (LNG) imports and Arctic gas. Both require the $3.00 to $3.50 price range.
The problem with a calculated average national equilibrium price of, for example, $3.25 gas is that it is made up of $1 to $10 fluctuations. Even when demand forces natural gas prices to the high levels that were observed in 2001, reservoir physics of the mature United States environment precludes a quick response. Thus, spikes of $10 gas cannot generate new domestic supply.
In a number of our previous writings, we have suggested that the trend toward natural gas as the premium fuel in the near future is not reversible. The key and the excruciating problem is the transition.
We examine in this paper a number of potential sources of natural gas, their limitations and potential. We also present a number of issues, which involve both national policy and rational business decision-making, to take the nation through the transition.
Managing the transition to natural gas is critical to the well-being of the nation and, considering the position of the United States on energy markets, the rest of the world. We finally show in this paper a stark example of the enormous impact of energy supply interruptions on the employment history of the United States, a situation, which may be the harbinger of major future economic hardships if the transition to natural gas is not managed properly.
Compositional Streamline Simulation
Authors: Jessen K. , Orr F. M. 
Published: December 2007

Abstract
Performance evaluation of miscible and near-miscible gas injection processes can be assessed through conventional finite difference (FD) compositional simulation. However, low-resolution compositional simulation is adversely affected by numerical dispersion and may fail to represent geological heterogeneities adequately, and high-resolution simulation is too expensive in computation time. The number of components can be reduced but at the price of less accurate representation of phase behavior.
Streamline methods offer another approach to high-resolution simulation. This paper reports results of combining an analytical, one-dimensional (1D) solution for multicomponent gas injection with a representation of flow along streamlines to capture the effects of heterogeneity. The 1D solution allows any number of components to be present in the injected gas as well as in the reservoir fluid. We report the results from combining the analytical 1D multicomponent solutions with 2D and 3D streamline simulators. A detailed comparison is given between the results of conventional FD simulation and the streamline approach. The comparison demonstrates that the CPU time requirement used in evaluation studies can be reduced significantly while at the same time reducing the adverse effects of numerical dispersion.
Drilling Waste Management: Past, Present, and Future
Authors: Veil John A. 
Published: December 2007

Abstract
The process of drilling oil and gas wells generates large volumes of drill cuttings and spent muds. The American Petroleum Institute estimates that in 1995, about 150 million barrels of drilling waste was generated from onshore wells in the United States alone. Onshore and offshore operators have employed a variety of methods for managing these drilling wastes, depending on what state and federal regulations allow and how costly those options are for the wells in question. In the offshore, the options are limited to discharge, underground injection, and transport back to shore for disposal. Onshore operators have a wider range of options--some wastes are managed onsite while others are removed to offsite commercial disposal facilities. The onshore waste management options employed include landspreading and landfarming, evaporation and burial onsite, underground injection, incineration and other thermal treatment, bioremediation and composting, and reuse and recycling.
Some drilling waste management practices used in the past did not protect the environment and public health to the extent desired and were later prohibited by regulatory agencies. This paper reviews some of those past waste management practices and indicates how wastes are currently being managed. Over time, state and federal regulatory requirements will become stricter, drilling and mud system technologies will advance, and some companies may voluntarily adopt waste management options that have even less environmental impacts that those in use today. The paper also discusses some possible drilling waste management practices that are likely to be employed in the upcoming decade.
Nuclear Magnetic Resonance While Drilling in the U.K. Southern North Sea
Authors: Appel Matthias , Radcliffe Nigel J. , Prabhakar Aadireddy , Bonnie Ron J. M. , Ridvan Akkurt 
Published: December 2007

Abstract
Standard formation evaluation of an exploration well in the UK Southern North Sea was supported by Magnetic Resonance While Drilling (MR-WD).
In this paper we show that even in tight gas sands, MR-WD provides information about porosity and producible fluid fraction, and allows estimation of formation permeability.
This successful introduction of MR-WD technology in a known hard-rock environment illustrates a powerful addition to the logging-while-drilling tool suite.
Applications of a New-Generation NMR Wireline Logging Tool
Authors: Heaton N. J. , Freedman R. , Karmonik C. , Taherian R. , Walter K. , DePavia L. 
Published: December 2007

Abstract
This paper discusses applications of a new-generation, nuclear magnetic resonance (NMR) wireline logging tool. The new design is a multi-frequency, eccentered, gradient-field NMR logging tool with multiple depths of investigation, which are maintained regardless of the hole size and are deeper than those of previous NMR logging tools. The new-generation tool features a high-resolution acquisition mode, making it possible to perform both fluid characterization and thin-bed analysis.
We present the results of MRF* Magnetic Resonance Fluid characterization logging in a range of different environments. MRF acquisition modes comprise suites of spin-echo sequences having sensitivity to molecular diffusion. Simultaneous analysis of an entire suite of data provides depth logs of oil viscosity and fluid saturations measured in the nearwellbore region as well as total porosity, T2 distributions, and permeability estimates.
Several logs acquired in different formations are used to demonstrate the high-resolution capability of the new tool. Data acquired in a test well with known characteristics are used to validate the vertical resolution, precision, and accuracy of the measurements.
A Method for Real-Time Well Clean-up Optimization
Authors: Waskoenig Hans-Heinrich , Langhans Grit , Miljenko Cimic , Heil Matthias , Antink Gerhard Hoog , Toskey Eric 
Published: December 2007

Abstract
A new technique to optimally clean-up wells has been developed. The method employs coiled tubing and pumped nitrogen to provide a controlled lift of the wellbore fluids, a multiphase flow meter to monitor from surface the results, and simulation software to model the process in real-time so that timely operational decisions can be made. This new technique was successfully applied to several challenging nearhorizontal extended reach well completions. The method can effectively clean out perforations and achieve an efficient displacement of the completion fluid out of the well. The control necessary to prevent damaging fragile formations and to minimize the risk of leaving bypassed completion fluid in a horizontal section is provided. The method also avoids the undesirable use of electrical cable in the coiled tubing to monitor the downhole conditions. Real-time surface fluid recovery and downhole nitrogen injection rates and volumes are obtained. Fluid lift simulations performed on-site during the lifting operation are history matched to actual well production data. Immediate adjustments to the lift can be made to optimize the well clean-up.
Relative Permeability Modification Using an Oil-Soluble Gelant to Control Water Production
Authors: Karmakar G. P. , Grattoni C. A. , Zimmerman R. W. 
Published: December 2007

Abstract
Water production in gas and oil wells is one of the major problems faced by the petroleum industry. Polymers and gels can be efficient materials for controlling excessive water production in gas and oil wells. The injection of gelant solutions into the near-wellbore formation can reduce the permeability of the formation to water much more so than to oil. Such gelants are known as relative permeability modifiers. In this experimental study, tetramethylorthosilicate (TMOS) has been used as the oil soluble gelant. TMOS is soluble in the oil phase, and reacts with water to form a semi-solid gel that is capable of modifying the permeability of the rock. As the water is transformed into gel, the permeability of the medium to water is reduced. Due to the increase in volume of the "water phase", the oil permeability is reduced to a lesser extent.
A series of static and dynamic gelation and flow experiments have been performed in test tubes. These were followed by flow tests conducted in transparent glass micromodels to determine the end-point relative permeability for oil and water before and after gelant injection. Our results show that the gel formation depends on the concentration of the gelant in the oil phase, the oil/water ratio, the amount of total gelant solution injected, and the time of flow of the gelant solution into the water phase. It was observed that the volume of gel obtained after gelation increases as the TMOS concentration increases, at a fixed oil/water ratio. The degree of permeability reduction for both oil and water is directly related to the amount of gelant injected. The results we have obtained can be used for pre-screening the efficiency of TMOS treatments.
A Study of Water Coning Control in Oil Wells by Injected or Natural FLow Barriers Using Scaled Physical Model and Numerical Simulator
Authors: Siddiqi Sarmad S , Wojtanowicz Andrew K. 
Published: December 2007

Abstract
A scaled physical model (radial sand pack) and a numerical simulator were used in this study to investigate the time-dependent development and dynamic shape of the water-oil interface around the well producing from a bottom-water-drive reservoir. The water cone development was then related to the monitored changes in oil production water-cut. Also observed was the effect of well completions (single or dual-with the bottom water drainage) on water coning in three different reservoir settings. The first was a homogeneous reservoir and was studied as a base case. The second scenario was an impermeable barrier injected around the well bore at the oil water contact (OWC). In the third setting natural heterogeneity was created comprising a low-permeability layer at OWC across the whole drainage area.
The study revealed that in the homogenous reservoir, using dual completion, it was possible to decrease water-cut in the oil production by draining water from the bottom completion and producing oil from the top completion. It was also established that the radial sand pack could be used to demonstrate visually the dynamic change in OWC with time.
The study showed that placing a man-made impermeable barrier around the well bore would not stop the water cone from forming. Water would simply flow around the barrier. Moreover if such natural barriers exist around the well, using dual completions for water control would not be effective.
It was also found out that the presence of a continuous low permeability layer across the reservoir would merely delay the development of water problem without eliminating it. Water breakthrough will be postponed and the water-cut will be reduced. It was also observed that the low permeability layer affects the shape of the cone in such a way as to increase the size of the base and make the tip of the cone narrow.
With increasing use of "smart completions" and injected barriers to control water coning, this study visually illustrates the limitations of these technologies. The results could help in selecting methods for specific reservoir conditions.