bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Neural Networks to Modeling Fluid Contacts in Prudhoe Bay
Authors: Panda Manmath N. , Zaucha David E. , Perez Godofredo , Chopra Anil K. 
Published: December 2007

Abstract
Modeling the dynamic behavior of fluid movement in an oil reservoir is complicated because of non-linear interactions between reservoir heterogeneity and fluid flow. Simple regression, geostatistical, and numerical simulation techniques have been used in the past to model fluid movement with various degrees of success. Most of these methods, however, suffer from common drawbacks that they are time consuming and difficult to automate. This paper presents a new method based on artificial neural networks (ANNs) to model dynamic gas-oil contacts in the Prudhoe Bay reservoir. This method is fast, efficient, and highly automated and requires minimum user intervention.
The proposed method uses oil, gas, and water production, perforation history, permeability, sand and shale distribution, and surveillance data at surrounding wells as ANN input to predict the fluid distribution a t a target well. A two-step method is developed to design an ANN. The first step trains the network using previously measured data as input and output, and thus establishing the internal rules of the network. The second step uses the trained network to estimate the fluid distribution at target wells. Results show that the ANN method can predict fluid distribution at target wells more accurately and consistently than conventional methods.
Selection and Installation of CRA-Clad Flowlines in the Madden Deep Unit
Authors: Craig B. D. , Eckroth J. J. 
Published: December 2007

Summary
This paper describes the selection and installation of corrosion-resistant-alloy (CRA)-clad flowlines and solid Alloy 625 piping wellhead tie-ins for hookup of wells in the Madden Deep Unit of Wyoming. The highly corrosive nature of the gas, coupled with the anticipated production of elemental sulfur and the close proximity to populated areas, dictated the use of these specialty materials. The special fabrication and installation requirements for CRA-clad flowlines, including some of the difficulties, are presented.
Scale Up of Heterogeneous Three Dimensional Reservoir Descriptions
Authors: Durlofsky L. J. , Behrens R. A. , Jones R. C. , Bernath A. 
Published: December 2007

Abstract
A general method for the scale up of highly detailed, heterogeneous, three dimensional reservoir descriptions is developed and applied. The method entails the nonuniform coarsening of the original detailed description, with finer resolution introduced in regions of potentially high flow rate (as identified through computationally efficient single phase flow calculations) and coarser, homogenized property descriptions applied throughout the bulk of the model. The method is applied to the simulation of three actual reservoirs and is demonstrated to provide coarsened reservoir models which give simulation results in close agreement with those of the original fine scale description but at considerable computational savings (speedups of nearly two orders of magnitude). In addition, it is shown that the method can provide geologically realistic coarse scale reservoir descriptions, which can be subsequently history matched to field data via geologically sensible modifications.
Modeling Gas-Condensate Well Deliverability
Authors: Fevang Øivind , Whitson C. H. 
Published: December 2007

Summary
This paper gives an accurate method for modeling the deliverability of gas-condensate wells. Well deliverability is calculated with a modified form of the Evinger-Muskat1 pseudopressure (originally proposed for solution-gas-drive oil wells). The producing gas/oil ratio (GOR) is needed to calculate pseudopressure, together with pressure/volume/temperature (PVT) properties (black-oil or compositional), and gas/oil relative permeabilities. The proposed method is successfully tested for radial, vertically fractured, and horizontal wells.
Using the proposed deliverability model, we show that fine-grid single-well simulations can be reproduced almost exactly with a simple rate equation that uses pseudopressure. The key is knowing the producing GOR accurately. The effect of near-wellbore damage, vertical fracture, or flow improvement caused by horizontal well trajectory is readily incorporated into the rate equation as a constant skin term.
The effect of gas/oil relative permeability is studied. We show that well deliverability impairment resulting from near-wellbore condensate "blockage" is dependent only on relative permeabilities within the range defined by 1 &lt;krg/kro &lt; 50. Usually this represents gas and oil relative permeabilities ranging from 0.05 to 0.3. Gas relative permeabilities at low oil saturations (krg &gt; 0.3) affect deliverability only for richer gas condensates.
A key observation and conclusion from this study is that critical oil saturation has no direct effect on well deliverability. We also show that interfacial tension (IFT) dependence of relative permeability has little or no effect on gas-condensate well performance (e.g., length of plateau production). The most important application of this study is to provide a simple method for calculating bottom-hole flowing pressure (BHFP) in coarse-grid models. We show that the proposed pseudopressure method is readily calculated for each well grid cell on the basis of only grid-cell pressure and saturation (i.e., producing GOR). Local grid refinement near wells is not necessary, and relatively large well grid cells can be used and still provide an accurate description of well deliverability.
Simulation of Linear Displacement Experiments on Massively Parallel Computers
Authors: Lee S. H. , Padmanabhan L. , Al-Sunaidi H. A. 
Published: December 2007

Abstract
We have developed a throat-bulb network model to simulate multiphase flow experiments. The model has been efficiently implemented on massively parallel computers (MasPar and CM5). This model has allowed us to study the dynamics of displacement processes. Using grids of size 64 × 64 × 128 (half a million cells), we are able to incorporate random variations in the throat and pore size distributions and observe flow patterns such as viscous fingering, stable front displacement, and invasion percolation. Furthermore, we are able to discern certain scaling rules in terms of macroscale variables.
Displacement processes in a network model with random distribution of throat and pore size can be characterized by three parameters: M (viscosity ratio), Ca (capillary number), and Cg (the ratio of capillary number and Bond number). Macroscale variables, Kr and Sor, are strongly dependent on flow patterns, whereas the dynamic capillary pressure, Pc, is independent of flow patterns.
Analysis of laboratory measurements of these macroscopic variables is generally based on steady state approximations and moreover, it offers no clue as to how one might extrapolate the results to the reservoir scale. Using the pore network simulator, we can model dynamic flow behavior and understand the scaling rules for experimental measurements. The simulator will eventually become a practical tool to investigate multi-phase flow in various flow conditions. Furthermore, a better understanding of experimental measurements will help us construct effective grid-block properties for reservoir simulation.
Experimental Verification of a Modified Scaling Group for Spontaneous Imbibition
Authors: Zhang Xiaoyun , Morrow Norman R. , Ma Shouxiang 
Published: December 2007

Summary
Spontaneous imbibition is of critical importance to oil recovery from fractured reservoirs. A widely used approach to predict oil recovery involves scale-up of laboratory results to reservoir conditions. Scaling involves the effects of sample size, shape, boundary conditions, viscosity and viscosity ratios, interfacial tension (IFT), pore structure, wettability, capillary pressure, and relative permeability. This work addresses the application of a characteristic length to scaling the combined effects of sample shape and boundary conditions with only minor variations in other parameters except for liquid/liquid (L/L) viscosity ratios.
Imbibition measurements are presented for cylindrical Berea sandstone cores of different lengths. For some experiments, core surfaces were partially sealed with epoxy to give different boundary conditions. Cores were initially saturated with refined mineral oils of different viscosities. A synthetic reservoir brine was used as the wetting phase. The characteristic length is defined as a function of bulk volume, areas of surfaces open to imbibition, and the distances from these surfaces to their respective no-flow boundaries. The characteristic length, in combination with a term that compensates for the effect of L/L viscosity ratio, gave close correlation of all data.
Dependence of Waterflood Remaining Oil Saturation on Relative Permeability, Capillary Pressure, and Reservoir Parameters in Mixed-Wet Turbidite Sands
Authors: Hirasaki G. J. 
Published: December 2007

Summary
The dependence of waterflood oil recovery on relative permeability, capillary pressure, and reservoir parameters was investigated by numerical simulation. The relative permeability and capillary pressure curves were based on laboratory measurements on unconsolidated sands. The "water-wet" case is based on the assumption that the system is water-wet and measurements were made with refined oil. The "mixed-wet" case assumed that the system is mixed-wet and restored-state measurements were made with crude oil. The reservoir model was a prototype turbidite sand with a range of thickness and permeability values. The economic oil recovery was based on an economic limit water cut of 50%.
The remaining oil saturation (ROS) in the swept region for the water-wet cases was close to the residual oil saturation. The ROS of the mixed-wet cases ranged from low values near the residual oil saturation to far above the residual oil saturation. It is dependent on the reservoir parameters that govern (1) the vertical "film surface drainage" of oil by gravity, (2) accumulation of a high oil saturation and thus a high relative permeability under the caprock, and (3) updip migration of the oil that accumulated under the caprock. The dependence on the reservoir parameters can be summarized by dimensionless groups. There is a dimensionless time for the vertical displacement of oil by gravity. The accumulation of a high oil saturation under the caprock is dependent on the ratio of the capillary transition zone and the sand thickness. The updip migration is dependent on a combination of the gravity number and the endpoint mobility ratio.
Well-Completion Audits To Evaluate Gravel-Packing Procedures
Authors: McLeod H. O. , Pashen M. A. 
Published: December 2007

SummaryData collected during gravel-packed completions may be analyzed to evaluate the impact of specific completion practices on well performance. Operations in which gathering data is critical are during the initial flow and perforation cleanup after underbalanced perforating; during prescribed injection tests before gravel packing; during periods in which fluid is being injected into the formation (pre-packing perforations, fluid loss after perforating, fluid loss after gravel packing); and during stabilized flow after the well is brought on line. This data can be used to calculate an approximate value for kh (md • ft) and an instantaneous completion efficiency at different stages of the completion. By comparing these instantaneous completion efficiencies, the damage contribution of certain operations and the damage-prevention aspects of other operations may be quantified. This methodology should provide a valuable resource to those pursuing continuous improvement in well-completion operations, particularly those involved in sand control.
Optimization of Balanced-Plug Cementing
Authors: Harestad Kristian , Herigstad T. P. , Torsvoll Arne , Nødland N. E. , Saasen Arild 
Published: December 2007

Summary
Placing properly balanced cement plugs in wells has been a serious problem to the drilling industry for decades. The cement plug is rarely found at the desired depth. Because of the fact that the cement slurry usually is more dense than the well fluid, the cement plugs are found deeper than anticipated, and the quality of the cement plug further down may be doubtful. This often results in setting a new cement plug to proceed with operations such as kickoff in the wellbore, abandonment, or pulling the blowout preventer. In the North Sea area cement plugs fail in more than 25% of the cases. Several techniques have been developed to keep the cement in place, but they are either very time consuming or they have a low degree of success.
A tool has been developed that is deployed below the cement plug, preventing the cement slurry from escaping down the well. This tool is very easy to install, does not take extra rig time and covers all sizes of hole diameters, from 152.4 to 584.2 mm (6 to 23 in.), with one tool. Before field application, the system was tested in full scale, where cement plugs were set in casings both with and without the new tool. The result from this testing showed that the new tool had a very high degree of efficiency compared to the reference tests that were performed without the tool. This paper presents the results from the tests and case histories where the tool was used.
Pulsed-Neutron Decay-Spectrum Data and Multi-lnflatable-Packer Plugdown Assemblies Improve Oil Production Rates
Authors: Schneider B. D. , Hogan G. P. , Holt W. N. 
Published: December 2007

Summary
A gravity-stable, vertical CO2-miscible-injection flood was implemented in the 824-ft-thick Wellman Unit Wolfcamp reef reservoir in July 1983. CO2 is injected in the crest of the reservoir to displace the oil vertically downward. The producing wells are constantly plugged down out of the "gassed-out" interval into the oil bank. This paper presents the results of the PND®-S through-tubing logging tool as a method to determine the CO2/oil/water contacts and the use of multiple-inflatable-packer/sliding-sleeve plugdown assemblies to achieve zonal isolation between gassed-out and producing intervals.
Short-Radius Horizontal Drilling System Optimization in Yates Field Unit Provides Excellent Directional Control and Highly Economical Completions
Authors: Tank W. J. 
Published: December 2007

Summary
Yates field unit in Pecos County, Texas, has recently drilled its 100th short-radius horizontal drainhole. The program has been a technical and economic success for the field, providing efficient completions in this highly fractured reservoir.
In the early stages of the program (1986–1990), short-radius drilling in Yates field unit was performed using strictly rotary drilling systems. In 1992, Odorisio and Curtis1 reported on the introduction of articulated downhole mud motors to the program and the impact of the initial modifications to the system. Since that time over 75 additional drainholes have been drilled. Two other drilling systems have been tested and many improvements have been made to the original system. This paper documents the optimization that has occurred in the drilling systems and the results obtained from this work.
Asphaltenes and Crude Oil Wetting—The Effect of Oil Composition
Authors: Buckley Jill S. , Liu Yu , Xie Xina , Morrow Norman R. 
Published: December 2007

Abstract
It is widely believed that asphaltenes and other high molecular weight, polar components of crude oils are responsible for altering the wetting of reservoir rocks, but the mechanisms by which wetting is affected are still uncertain. The concentration of asphaltenes in an oil is not necessarily a good predictor of rock/oil interactions. The composition of the remainder of the oil phase is equally important, particularly with regard to its properties as a solvent for some of its largest constituents.
Solvent quality of the crude oil mixture is a function of composition, temperature, and pressure. Changing solvent quality by addition of an excess volume of low molecular weight paraffins is the basis for definition of the asphaltenes, the material that precipitates from the diluted mixture. The extent to which wetting is altered in oil/brine/rock systems by adsorption of asphaltic material from the crude oil is affected by changes in oil solvent properties, even in mixtures in which the asphaltenes are stable with respect to precipitation.
A simple approach, using measurements of mixture refractive index, is applied to quantify oil solvent quality for mixtures of crude oil or asphaltenes with hydrocarbon additives. Wettability alteration with systematic changes in oil composition is evaluated by contact angle measurements. Crude oils generally induce greater alteration as they become poorer asphaltene solvents.
EOR Screening Criteria Revisited— Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects
Authors: Taber J. J. , Martin F. D. , Seright R. S. 
Published: December 2007

SummaryScreening criteria have been proposed for all enhanced oil recovery (EOR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only CO2 flooding activity has increased continuously.
Gulf of Mexico Horizontal Well Improves Attic-Oil Recovery in Active Waterdrive Reservoir
Authors: Vo D. T. , Marsh E. L. , Sienkiewicz L. J. , Mueller M. D. , May R. S. 
Published: December 2007

Summary
This paper presents a Gulf of Mexico field case study describing the use of horizontal wells to improve oil recovery in thin attic-oil, strong waterdrive reservoirs. Prewell planning shows the use of reservoir simulation for well performance forecasts, discusses selection of drilling mud for minimal damage, logging while drilling (LWD) for steering and optimal completion techniques. Post-well results show that horizontal wells, applied with an integration of technology, not only help accelerate production but also improve oil recovery compared with conventional wells for this type of reservoir problem.
3D Modeling To Optimize Production at the Successive Stages of Field Life
Authors: Taylor S. R. 
Published: December 2007

Summary
Production optimization requires a clear understanding of subsurface conditions throughout the field's life. Description of the subsurface through classical 2D techniques is being replaced increasingly by powerful computer technology. Such technology enables construction of fully numeric 3D models of the subsurface, which can be visualized through high-end graphics displays. This 3D modeling technology is having a significant impact on development planning and monitoring activities.
The focus here is on the perceived benefits and challenges of using 3D models to optimize production. The paper includes examples of integrated 3D static and dynamic modeling activities carried out on fields undergoing appraisal and development and fields facing abandonment.
Case 1 (appraisal) illustrates how the integrated use of 3D static and dynamic modeling during primary development enables petroleum engineers (PE's) to construct alternative reservoir models rapidly and to evaluate the impact of various uncertainties quantitatively. This approach optimizes production by facilitating fast-track developments, design of robust development schemes incorporating optimized well paths, and providing quantified justification for appraisal expenditure.
Case 2 (mid field life) illustrates the benefits of using 3D modeling technology to integrate static and dynamic field data, geological knowledge, and scenario analysis concepts to locate bypassed oil and optimize infill well trajectories. History matching offers the geologist valuable feedback on the robustness of the geological model, including aspects such as the size and orientation of reservoir sands. The relative impact of various uncertainties can be quantified and development schemes optimized.
Case 3 (end field life) illustrates how, even in very mature fields that are facing abandonment, 3D modeling technology can facilitate data integration with subsequent cross-discipline interpretation. This leads to the successful planning and drilling of horizontal sidetracks to develop bypassed oil.
In all cases, the technology used allows sophisticated 3D models of the subsurface to be built through integration of diverse data types and geological knowledge. The resultant models can be upscaled rapidly for dynamic simulation; model optimization through iterative feedback from the reservoir flow simulator can be achieved easily. The facility to plan and "drill" wells in the 3D volume enables development scenarios to be optimized both in terms of well trajectory and multidisciplinary teamwork.
Determining the Parameters of the Forchheimer Equation From Pressure-Squared vs. Pseudopressure Formulations
Authors: Civan Faruk , Evans R. D. 
Published: December 2007

Summary
This paper presents a comparison of the accuracy of the pressure-squared and pseudopressure formulations of the Forchheimer equation for simultaneous determination of the permeability and non-Darcy flow coefficient from high-velocity flow tests using core plugs. We show that the pressure-squared formulation must satisfy two contradictory conditions. The core length should be sufficiently small so that the average viscosity and real gas deviation factor, which are dependent on the pressure drop, approach the actual values. The core length, however, should be long enough to be representative of the characteristic length of the porous media. Because these two conditions cannot be met simultaneously, the pressure-squared formulation is less accurate. We show that these effects are more pronounced for tight formations because of higher pressure drop across the core. The pseudopressure formulation requires only that the core length should approach the representative core length, and, therefore, it provides more accurate interpretation of the high-velocity core flow tests and generates accurate values of the permeability and non-Darcy flow coefficient and the representative core length.
Development and Application of PDC Core Bits for Downhole Motor Low-Invasion Coring in the Arab Carbonates
Authors: Rathmell J. J. , Wilton B. S. , Gale B. A. , Bell D. A. , Tibbitts G. A. , Bobrosky D. J. 
Published: December 2007

Summary
A method has been developed for low-invasion, downhole motor coring in the Arab formation, Arabian Gulf. Motors were used for the first time in the Arab formation to achieve higher bit rotational velocity and higher coring rate for low filtrate invasion when using a water-based mud.
Earlier, a field test of motor coring with pre-existing low-invasion core bits showed that antiwhirl core bits were superior to other core bits at high bit-rotation rates. Two new antiwhirl, low-invasion core bits with improved polycrystalline diamond compact (PDC) cutters were designed and laboratory tested for coring the Arab carbonates and anhydrites. Laboratory coring tests indicated a two-fold increase in coring rate for the new core bits with a motor compared to use of only the top drive.
The low-invasion water-based coring mud and core bits tested in the laboratory have been used to cut 278 ft of core on the Al-Rayyan field in the Qatari section of the Arabian Gulf. A downhole motor and top drive provided rotational rates at the core bit exceeding 200 rev/min compared to 100 rev/min with top drive alone. Motor coring has provided a two-fold coring-rate increase. Core quality was excellent, and core recovery was 99% with low filtrate invasion confirmed by potassium iodide tracer. Well-log and capillary pressure-derived water saturations agree with the core.