bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation of Gravity Override in Foam Processes in Porous Media
Authors: Shi J.-X. , Rossen W. R. 
Published: December 2007

SummaryFoam can improve sweep efficiency in gas-injection improved-oil-recovery processes. The success of continuous-injection foam processes in overcoming gravity override in homogeneous, anisotropic (kx ≠ kz), radial or rectangular reservoirs depends on a single dimensionless number first proposed by Stone and Jenkins for gas flooding without foam. Their model fits foam-simulation results remarkably well over a wide range in reservoir properties and geometry, flow rates, foam quality and strength, initial reservoir pressure, and model for the mechanisms of foam collapse. This approach leads to optimal design strategies for such processes. Limitations on injection-well pressure may make it impossible, however, for a continuous-injection foam process to suppress gravity override in some cases. The possibility of gravity override within the foam bank should be considered in evaluating foam propagation in field trials of foam processes.
Results of Using Formaldehyde in a Large North Slope Water Treatment System
Authors: McLelland W.G. 
Published: December 2007

Abstract
In an effort to alleviate severe injection well plugging at Prudhoe Bay, formaldehyde treatment of the Flow Station 2 produced water was initiated in early 1991 and continued through mid 1995 when the program was terminated. Formaldehyde was selected because of its biocidal properties and cost. The results of these treatments are discussed in terms of the overall effect of formaldehyde on the system. Other events that impacted produced water quality at the facility, and subsequently the results of the formaldehyde program, are also discussed.

Introduction
The Prudhoe Bay Field is jointly operated by Arco Alaska, Inc. and British Petroleum Exploration on behalf of the Prudhoe Bay co-owners. ARCO is operator of the EOA (eastern operating area) which consists of three oil, water, and gas separation facilities termed Flow Stations. The Flow Station 2 facility handles fluids and gas produced from the eastern most area of the field and production is waterflood dominated.
The source water for the Prudhoe Bay waterflood was initially seawater. However, as breakthrough occurred, produced water was re injected as part of the flood with a corresponding decrease in seawater.
In 1990, additional produced water handling equipment was added at Flow Station 2 in order to treat the expected 700 KBWD peak water production anticipated before the end of flood life. The new treating equipment is set up to allow the separated produced water from the slug catchers and chem-electric treaters to gravity feed into an 18 Kbbl cone bottom tank (81 tank) with sand jet capabilities. The produced water stream exiting this tank is then split and the fluid enters two 12 Kbbl tanks (82 & 83 tanks) designed for free oil removal by gravity segregation. From these tanks, the fluid stream is recombined and fed into a header. The header feeds the produced water stream into four rotor type dispersed gas flotation cells (GFCs). The water from the flotation cells is directed through a series of pumps and ultimately to the produced water distribution piping for re-injection into the formation as part of the waterflood.
Concurrent with the startup of the new treating facilities, there appeared a sharp increase in the volume and severity of a black amorphous solid material in the produced water system and reports of "black water" caused by iron sulfide. This material collected in the facility and in the injection wellbores creating numerous problems with severe oil carryover, level controllers, pump strainers and seals, and routine well work. The buildup in the wellbores became so severe that it was virtually impossible to run any type of tool into an injection well without first cleaning out the wellbore.
A Semi-Analytic Method for Thermal Coupling of Reservoir and Overburden
Authors: Weinstein H.G. 
Published: December 2007

Abstract
A semianalytic method of handling the energy balance solution in the overburden has been developed. The method results in a single overburden energy coupling equation applicable at the reservoir - overburden boundary. This feature facilitates simultaneous solution of the pressure and energy equations in the reservoir. Test problems show the semianalytic method to compare favorably with the fully finite-difference technique. Both reservoir - overburden boundary temperature and the important factor of beat transfer into the overburden are accurately predicted by the method. predicted by the method. The semianalytic procedure may have considerable usefulness in the solution of reservoir problems. The method can definitely be applied in thermal simulation programs. Other anticipated applications are to an aquifer underlying a reservoir, an overlying gas cap, or to increasing definition in the vicinity of a wellbore. In each of these applications, the semianalytic procedure is expected to be considerably faster than the finite - difference solution.

Introduction
In thermal reservoir simulation programs, the material balances are solved over the reservoir; the energy balance is solved over the underburden-reservoir-overburden system. Hence, to avoid excess storage and computation time requirements, the material and energy balances are generally not solved simultaneously. In many cases it would be desirable to solve simultaneously the material balances (or equivalently, the pressure equation obtained by combining the material balances to eliminate saturation) and the energy balance. Problems with solution convergence and the treatment of mass transfer terms could be avoided in this way. This paper describes a semianalytic method of handling the energy balance solution in the overburden (and underburden). This solution results in a single overburden energy coupling equation that can be solved easily in conjunction with the reservoir pressure and energy equations. pressure and energy equations. The paper presents the mathematical development of the method and shows results for several test problems. The problems are similar to those encountered in thermal recovery processes. They compare the semianalytic method with the fully finite-difference procedure and, in one of the problems, with a completely analytic procedure and, in one of the problems, with a completely analytic solution.
A Scaleable, Database Architecture for Storage of PVT Data
Authors: Jefferson L. L. , Nighswander J. A. , Chang-Yen D. A. 
Published: December 2007

Summary
Convenient access to fluid-property data in electronic form is currently not available in many petroleum organizations. Ready access to this information could result in significant cost savings by reducing the need for repeated studies and reducing the scope of new studies by analogous fluid evaluation. This work presents an overview of the development of a new scaleable database application to address these issues. In addition, we discuss design and development issues related to database scaleability. The application, PVT ReCORD, is currently undergoing beta testing by a major commercial laboratory that is creating an on-line fluid-property repository and automating pressure/volume/temperature (PVT) report generation with this tool.
An Interactive 3D Fracture-Modeling Environment
Authors: Swaby P. A. , Rawnsley K. D. 
Published: December 2007

Summary
We describe an original three-dimensional (3D) fracture-modeling environment that is designed to allow users to construct interactively near-well fracture models suitable for use as input to fluid-flow simulators. Data input consists of a surface model of the seismic-scale structure, well-fracture data, and user-defined parameters. Sedimentary discontinuities and faults can be extrapolated from the wells in three dimensions (3D). Within this near-well model, tension fractures can be generated by use of a genetic process that aims to reproduce the initiation, growth, and interaction of fractures to create realistic fracture systems. Graphs are available for calibrating the fractures to assumed statistical distributions.
A Statistical Study of Rheological Models for Drilling Fluids
Authors: Weir Iain S. , Bailey William J. 
Published: December 2007

AbstractIn order to determine laminar friction losses of non-Newtonian drilling fluids it is standard practice to utilise a simple rheological model with parameter estimation via explicit solution of the required number of simultaneous equations. This limits the choice of available models and, together with the fitting procedure, frequently results in poor fits. Numerous alternative models have been proposed, but their worth has never been clearly demonstrated. Here we consider the rheological models to form the deterministic part of a stochastic model hence acknowledging that observed data arise from randomness due to the system. Parameter estimates are obtained by nonlinear least squares using data readings from eight standard Fann viscometer settings. Results are presented for 20 rheological models on 414 Fann viscometer data sets that encompass a variety of different drilling fluids. The goodness of fit of the models is assessed by comparing boxplots of the resulting residual mean square values. Several of the alternative models are shown to be consistently capable of excellent shear stress prediction over all of the shear rate range expected during drilling operations. The use of statistical methodology allows us to go beyond mere data relationship estimation: it permits the calculation of confidence intervals and tests of significance of functions of the model parameters, for example equivalent circulating density. The validity of such calculations relies on the extent to which the behaviour of the nonlinear least squares estimates approximates the asymptotic properties of being unbiased, normally distributed and minimum variance estimators. The estimation behaviour of the ‘best’ fitting models is analysed and a reparameterised form of the Sisko model is identified as having reasonable behaviour. Thus, despite the small data size, when using this model form the subsequent estimates, confidence intervals and tests of significance of functions of the model parameters can be confidently reported.
The Phase and Volumetric Behavior of Natural Gases at Low Temperatures and High Pressures
Authors: Davis P.C. , Bertuzzi A.F. , Gore T.L. , Kurata F. 
Published: December 2007

Abstract
The phase and volumetric properties of 10 very volatile mixtures are presented for temperatures from - 200 degrees F to above the critical points. These mixtures consisted of natural gases and of mixtures of natural gases with methane and nitrogen. Existing correlations of compressibility factors have been extended to apply to these mixtures. Existing correlations of critical pressures and temperatures do not apply to these mixtures. Methods have been developed for estimating critical temperatures of these mixtures to +/- 4 degrees F and critical pressures to +/- 5 per cent. These methods apply to other volatile and very volatile mixtures.
The results of this work are particularly applicable to the separation of nitrogen from hydrocarbons by low-temperature distillation.

Introduction
Knowledge of the low-temperature phase and volumetric properties of natural gases and of other mixtures of the light hydrocarbons is becoming increasingly important as interest in low-temperature separation processes increases. Low-temperature distillation has been used to separate ethane and ethylene from natural gas and from refinery gases for petrochemical uses. Removal of nitrogen from natural gas by low-temperature distillation has been proposed as a means of increasing the capacity of existing gas transmission lines and of improving the marketability of the gas.
Further application of low-temperature separation processes has been retarded by lack of data on the phase and volumetric behavior of mixtures at low temperatures and at high pressures. This paper presents the results of determination of the phase and volumetric properties of 10 very volatile mixtures at temperatures from - 200 degrees F to above the critical point. These mixtures consisted of natural gases with methane and nitrogen. Generalized methods are presented for estimating the critical temperatures, critical pressures, and the densities of such mixtures.
Numerical Laplace Transformation of Sampled Data for Well-Test Analysis
Authors: Onur Mustafa , Reynolds A. C. 
Published: December 2007

SummaryIn recent years, the numerical Laplace transformation of sampled data has proven to be useful for well-test analysis applications. However, the success of this approach is highly dependent on the algorithms used to transform sampled data into Laplace space and to perform the numerical inversion. We present new algorithms to accurately transform sampled data into Laplace space and to minimize "tail effects" resulting from the extrapolation of tabulated data. The algorithms presented can be applied to generate accurate pressure-derivative data in the time domain. We show that performing curve-fitting (without inversion) in Laplace space with the algorithms presented is computationally more efficient than performing it in the time domain. Applications of the algorithms to convolution, deconvolution, and parameter estimation in Laplace space are also presented. Both synthetic and field examples are considered to illustrate the applicability of the proposed algorithms.
Pore Network Model for Foam Formation and Propagation in Porous Media
Authors: Kharabaf Hooshang , Yortsos Yanis C. 
Published: December 2007

SummaryA simple pore-network model, based on a pores-and-throats representation, is developed to simulate the generation and mobilization of foams in porous media. Contrary to previous works, the model simulates a dynamic invasion process, in which gas invades a porous medium occupied by a surfactant solution. For the front to advance, the applied pressure gradient needs to be sufficiently high to displace a series of lamellae along a minimum capillary resistance path. We determine this path using a novel algorithm simulating invasion percolation with memory (IPM).1 We focus on the properties of the displacement, the onset of foam flow and mobilization, the foam texture and displacement efficiencies and the fractions of flowing and trapped lamellae, as a function of parameters, such as the snap-off probability. Comparison with experiments shows a generally good agreement, despite the simplicity of the model. The invasion by foam of low permeability layers during injection in a heterogeneous system is also demonstrated.
A Pilot Test of Polymer Flooding in an Elevated-Temperature Reservoir
Authors: Tielong Chen , Zhengyu Song , Fan Y. , Changzhong Hu , Ling Qiu , Jinxing Tang 
Published: December 2007

Summary
We conducted a pilot test of polymer flooding in the Shuanghe reservoir located in the southeast Henan oil field, China. The target reservoir has a net thickness of 15.56 m (50 ft), an average permeability of 420 md, and a temperature of 75°C (167°F). The polymers used are two types of modified partially hydrolyzed Polyacrylamides, named S525 and S625, which have molecular weights of 16,700,000 and 19,670,000 daltons, respectively. The objective of this pilot test is to investigate the feasibility of polymer flooding for improving oil recovery in an elevated-temperature reservoir.
The polymer flooding started in February 1994. Through December 1995, a total of 246 tons (about 0.5 × 106 lbm) of dry polymer had been used with an injection concentration of 900 to 1,100 ppm. The pore volume (PV) injected reached 0.2164. As a result, oil production increased by 22,000 tons (184,000 bbl) and water production decreased by 153,000 tons (962,000 bbl), which accounts for the incremental oil recovery of 3.8% and water-cut reduction of 5.6% in the test block. We estimate that, by the end of this project, the ultimate increase in oil production will exceed 63,000 tons (528,000 bbl) with the enhanced oil recovery going up to 9.8%. The yield is 0.2 tons more oil produced per kilogram of polymer injected or 0.7 barrel of oil produced per pound of polymer.
We attribute the success of the pilot test to the techniques used during the implementation of the flooding, including prevention of polymer-thermal degradation, good reservoir description, and the profile modification carried out before and after the polymer injection. This pilot test illustrates a case where polymers with extra-high molecular weight are successfully injected in an elevated-temperature reservoir to control the mobility ratio and modify the permeability profile.
A New Approach to Forecasting Miscible Water Alternating Gas Performance at the Field Scale
Authors: Giordano R. M. , Redman R. S. , Bratvedt Frode 
Published: December 2007

Summary
Full-field enhanced oil recovery (EOR) performance predictions are generally obtained from scale-up tools, because three-dimensional (3D) finite-difference simulations would be too CPU-inten- sive. Existing scale-up techniques require the user to define pattern elements and then to derive performance curves to apply to each injector-producer pair in the elements. Accurate assignment of these elements is difficult because the actual shape and size of the swept volumes are sensitive to reservoir faulting, well-rate changes, and regional flux. In reality, the actual sweep region is not an input parameter, but should be determined by the regional pressure field, which changes as well rates vary and new wells are drilled. Thus, a major source of error in using existing scale-up tools is trying to define representative pattern elements. In the current paper, we describe a scale-up technique in which the user does not have to define pattern elements or injector-producer pairs. In the new technique, the pressure field is computed at each timestep and then a front-tracking algorithm propagates water and miscible injectant throughout the reservoir. The miscible-gas process is modeled by means of an analogy between oil mobilization and adsorption/ desorption of tracers. The parameters for the model are obtained by fine-scale, two-dimensional (2D), compositional, finite-difference simulations in a vertical cross section. In the new approach, the injected solvent is divided into an effective and an ineffective portion. This approach reduces a 3D problem to a 2D, areal one in which the declining displacement efficiency of the solvent, which is caused by vertical effects, is captured by decreasing the injected concentration of effective solvent with time. In this paper, we show how the new scale-up tool has been used to model the miscible water-alternating-gas (MWAG) process in the Eastern Peripheral Wedge zone (EPWZ) of the Prudhoe Bay field. We show a comparison between field response and model predictions.
Advanced Tools for Advanced Wells: Rotary Closed-Loop Drilling System-Results of Prototype Field Testing
Authors: Poli Sandro , Donati Franco , Oppelt Joachim , Ragnitz Detlef 
Published: December 2007

Summary
In the next few years, a revolutionary well-steering system will arrive to face the "advanced wells" challenge. After an extensive period of field testing, the "rotary closed-loop system" (RCLS) seems very close to having the capability of operating in any extended-reach, deep horizontal, or complex multilateral well and in a high-pressure/high-temperature (HPHT) environment. Additionally, mainly because of the elimination of a sliding operation, conventional directional wells will, in many cases, also greatly benefit. The RCLS was designed to control automatically well geometry during directional drilling, even while rotating the drill-string. Hydraulically powered, electronically controlled, expandable ribs, which generate a radial steering contact force to the borehole wall, adjust the wellpath. All parts, except a short steering sleeve, work continuously in rotation. The RCLS may be operated with or without a downhole motor. Several subsystems, e.g., the hydraulic components, most electronic modules, and the bottom-to-surface communication, were field tested during 1994 and 1995. The first field trial of the complete unit, drilling a total of 1067 m, was conducted in late 1995 at Montrose, Scotland. The field test program was continued in early 1996 to compare RCLS drilling and directional performance with the introduction of broadened operating parameters. During this prototype testing period, the efficacy of all major functions was fully verified.
Innovative ESP Completions for Liverpool Bay Development
Authors: Stewart D. R. , Holland Brian 
Published: December 2007

Summary
This paper presents a review of the electrical-submersible-pump (ESP) completions installed in the Douglas field in Liverpool Bay-A number of innovations were introduced into the completion design successfully. These are discussed, along with the completion procedures and the excellent operational performance that was achieved during initial completions. ESP-runlife performance and the steps taken to maximize runlives are also discussed.
Selecting the Proper Rotary Rock Bit
Authors: Estes Jack C. 
Published: December 2007

Introduction
On Aug. 10, 1909, Howard R. Hughes patented the first rotary rock bit, which he called a "boring drill." The drill resembled two pipe reamers set on journal bearings attached to a drillpipe sub. This invention enabled rock formations to be drilled and was the starting point for 62 years of rock-bit development. This development history is traced in Fig. 1. It is not our purpose here to discuss these changes, nor to detail the basic designs of rock bits. The major bit manufacturers provide, for the asking, very good manuals on this subject. It is our purpose to provide the engineer who plans casing and drilling programs with the plans casing and drilling programs with the information he needs to take advantage of the most modern bit technology. Casing programs that force the use of obsolete bit types, and drilling programs that do not run the new bits properly are programs that do not run the new bits properly are more costly than they need be. Optimization of drilling is coming into its own after 10 years of intensive development. Often, however, the optimization procedures are handicapped by preset casing programs that force the use of off-size or obsolete bits. How good is modern bit technology? If you are drilling a "standard" hole size, the answer is "great." We are drilling footages and hours on single bits that would have been unbelievable just 2 years ago. Many of the new design features, which were experimental in the early 1960's, have been made generally available in the last 4 years. As shown in Fig. 1, it is estimated that improvements in rock bit development have been 30 percent greater in the last 4 years than in the 50 previous years. In fact, some optimum drilling programs planned just last year for ultradeep wells have become obsolete before the wells have been completed because of the introduction of new types of bits that were not generally available when the wells were originally planned. planned. Roller-Rock-Bit Classification
Complete rock-bit nomenclature can be found in most bit catalogs and, therefore, will not be introduced here. However, several terms should be described for the following discussion. Rock bits are usually classified according to tooth material and height, cone offset, and journal angle. The teeth may be hard-faced, case-hardened, or inserts of tungsten carbide. The cone offset, sometimes called "skew," is a measure of how far the center line of a cone misses the center of the bit. Journal angle is the angle the center line of the bearing journal makes with the bottom of the hole. A rock bit may be built with any one of four different types of bearing assemblies: nonsealed roller, sealed roller, sealed journal, and "super" journal, with the price increasing in the order listed. A rock-bit classification guide based on these features for the four major bit manufacturers is given in Table 1. Bits on the same fine in the chart are designed to withstand roughly the same operating conditions.
JPT
P. 1359