bluuebunny/crossref_metadata_2025_split huggingface dataset:
Big Muddy Water Flood
Authors: Haller R.W. 
Published: December 2007

Abstract
This paper presents a summary of the production and waterflood history of the Second Wall Creek Reservoir in the Big Muddy field. This highly successful Eastern Wyoming water flood has doubled the production from the Wall Creek in less than two years of operation. An outline of the laboratory and reservoir studies which culminated in the installation of a pilot water flood in 1953 is presented. Pertinent reservoir data, such as oil and water saturations, are given. The development program and current production practices of the waterflood program are also presented. The primary and waterflood performance is shown for several individual wells and for the entire flood. Cumulative waterflood recoveries and the estimated ultimate recoveries are given, in conjunction with the current development and operating costs and the future economics of the waterflood program.

Introduction
The Big Muddy oil field is located about 4 miles west of Glenrock in Converse County, Wyo. The field was discovered in 1916, although Wall Creek production was not encountered until 1917, when State 10 Lease Well No. 1 was brought in flowing at a rate of 150 BOPD. This discovery touched off a prolific drilling program and brought about one of Wyoming's famous oil booms. Most of the wells drilled to the Wall Creek were located along the crest of the structure and were generally spaced on a 10-acre pattern as shown in Fig. 1. Full development of acreage did not take place on leases located on the flanks of the structure. However, lease line drilling was sufficient to prove up this peripheral area. The majority of wells were drilled with cable tools to the top of the sand. Casing was then run and the wells tailed in to a depth 50 to 60 ft below the sand top. A typical casing program consists of 40 ft of 20 in. surface pipe, 250 ft of 15 1/2 in. pipe to seal off a good water sand, 1,000 ft of 12 1/2 in. pipe to combat hole cavings and finally 3,000 ft of 6 1/4 in. casing set on top of the sand. There is little record of cementing having been done in the early wells.
The Effect of Linear Pressure Trends on Interference Tests
Authors: Kamal Medhat 
Published: December 2007

In analyzing the results of an interference test, the pressure change at the observation well usually is regarded pressure change at the observation well usually is regarded as the effect of the producing wells only. The existence of any other trend in the reservoir pressure will cause errors in the values of the reservoir properties deduced from the interference test unless the effect of this pressure trend is considered in the analysis of the test results. One of the important advantages of pulse testing over the conventional interference test is that the pulse test response can be detected easily from unknown trends in the reservoir pressure.
The purpose of this article is to show the effect of a linear pressure trend on interference tests. The physical reservoir considered in this study is an infinite, homogeneous, isotropic, porous medium of uniform thickness filled with a single-phase fluid that has a small and constant compressibility and a constant viscosity. The porosity and permeability of the porous medium are assumed to be independent of pressure. The porous medium are assumed to be independent of pressure. The flow of the fluid through the porous medium is assumed to be isothermal radial flow into or out of a well open over the entire thickness of the porous medium. The pressure gradient is assumed to be small and the gravity forces are assumed to be negligible.
Injection of q STB/D was started in a well at time t=0 and the pressure response was recorded at the observation well. The pressure at the observation well as a function of time can be represented by Eq. 1(1)...
or, in dimensionless form.,(2)...
where,(3)...(4)...
The dimensionless pressure at the observation well was calculated for values of dimensionless time ranging from 0 to 3. This range was used because that is the time required to run a pulse test on a reservoir with average properties. The dimensionless pressure at the observation well also was calculated assuming that there were several linear trends in the reservoir pressure in addition to the effect of the injection of q STB/D in another well. Different slopes were used for the linear pressure trend. These slopes were chosen such that the change in the dimensionless pressure ranged from 10 to 30 percent. The results of these calculations are shown below.
The errors in analyzing the results of the interference tests, errors caused by the existence of the linear trends in the reservoir pressure, were found by matching the type curves that resulted in each case with the type curve of the pressure response at the observation well in absence of linear trends in the reservoir pressure. Fig. 1 shows this match for the case of a 30 percent change in pressure.
P. 1383
Compressibility Factors for CO2-Methane Mixtures
Authors: Simon R. , Fesmire C.J. , Dicharry R.M. , Vorhis F.H. 
Published: December 2007

Compressibility factors from a high-ratio CO2-natural gas mixture are compared with other experimental data and values calculated using two correlations. Discussion includes the use of these factors in monitoring reservoir performance for the SACROC Unit CO2 injection project.

Introduction
The SACROC Unit CO2 injection project in Scurry County, Tex., required transporting 200 Mcf/D of CO2 for 200 miles. A feasibility study of the mode of transportation resulted in selection of a "supercritical-pressure-state" pipeline system.
A study was made of available data on compressibility (z) factors for CO2-natural gas at supercritical pressures, as well as of two engineering calculation methods. This study indicated that the z factors should be measured rather than taken from published information.
This paper compares our measured compressibility factors with calculated and published compressibility data, and describes applications of z factors to the various phases of the SACROC Unit CO2 injection project. phases of the SACROC Unit CO2 injection project. Experimental PVT Data
There were two reasons for measuring z factors rather than relying on published information:Reamer et al.'s data for the CO2-methane system did not include C2+, which is contained in the pipeline gas.For engineering purposes, corresponding-state and equation-of-state calculation methods are not accurate enough near the critical point. CO2 pipeline design conditions include the critical point.
Our measurements were made in a visual PVT cell using the CO2-natural gas mixture described in Table 1. Conditions ranged from 680 to 3,001 psia and 49 to 120 degrees F. Tables 2 and 3 and Fig. 1 show the experimental results along with the calculated values and Reamer et al.'s data.

Experimental Method
The gas used for the compressibility-factor measurements was prepared from pure compounds. It was analyzed by determining the CO2 in an Orsat apparatus (thus removing the CO2) and chromatographing the re-reminder of the gas.
The liquid-vapor, two-phase boundary of the gas was estimated, and the gas pressure was kept above the cricondenbar to insure single-phase transfer from a storage vessel to the visual PVT cell.
In the visual cell, the pressure was decreased in steps and the volume was measured at each step. This pressure-volume relation was determined at 49, 70, 90, and pressure-volume relation was determined at 49, 70, 90, and 120 degrees F. At 49 and 70 degrees F we observed bubble points and a dew point. Compressibility factors were points and a dew point. Compressibility factors were calculated from the pressure, volume, and temperature values (z = pV/RT).

Experimental Results
Table 1 shows the analysis of the gas used, along with the measured specific gravity and volumetric expansion values. Table 2 shows the measured z factors for the four temperatures. These data are plotted in Fig. 2 with the observed bubble and dew points.
JPT
P. 81
A Flowmeter for Measuring Subsurface Flow Rates
Authors: Newman J.L. , Waddell C. , Sauder H.L. 
Published: December 2007

Abstract
An instrument capable of measuring subsurface flow rates is described. The instrument is self-contained and may be run on piano wire line. It detects flow by means of an impeller suspended between two torsion wires. The force of the well fluid striking the impeller causes the impeller to rotate, exerting a torsional force to the wires. This force is determined by recording the angle of rotation of the impeller on film using a battery-driven, clock-controlled camera. The impeller is sensitive to flow in either direction and the same instrument can be used to measure injection as well as production rates. Changes in direction of flow, such as might be caused by thief zones, are measurable and are indicated by a reversal of the direction of rotation of the impeller. Adjustment of the sensitivity of the instrument to measure a wide range of flow rates is accomplished by the use of different size torsion wires. An umbrella-type fluid trap, which contacts the casing or wellbore, diverts the flow through the flow tube. The fluid trap remains closed while running in the hole and can be opened at any point in the well. The instrument with the trap closed is 1¾ in. OD and may be run through 2 in. tubing. Successful flow profiles have been made on wells with flow rates ranging from 60 B/D to 4,000 B/D at surface pressure up to 4,500 psi. The instrument is designed for high-pressure and high-temperature operations.

Introduction
The need for an instrument that will measure flow rates in a wellbore is as old as reservoir engineering itself. A number of such devices have been designed within the past few years. Some of these have been described in the literature. One of these devices, a hot-wire anemometer type, made many successful jobs in dry gas producing areas. Difficulty was encountered when this flowmeter was used in wells producing liquids and development work was initiated to overcome this difficulty. The present flowmeter is the result of this work and provides an instrument with a wider range of application in the industry.
Simulating Residual Saturation and Relative Permeability in Heterogeneous Formations
Authors: Paterson Lincoln , Painter Scott , Zhang Xiaodong , Pinczewski W. V. 
Published: December 2007

SummaryNetwork models are used to investigate the effect of correlated heterogeneity on capillary dominated displacements in porous media. Residual saturations and relative permeabilities are shown to be sensitive to the degree of correlation and anisotropy. The network models reproduce the experimental observation that relative permeability is greater in the direction parallel to the bedding compared with perpendicular to the bedding. The scatter commonly observed in core measurements of residual saturation may be attributed to the presence of correlated heterogeneity in actual reservoir rocks.
Improved Two-Phase Model for Hydraulic Jet Pumps
Authors: Noronha F. A. F. , França F. A. , Alhanati F. J. S. 
Published: December 2007

Summary
A new model is proposed to predict the performance of hydraulic jet pumps (HJP's) when pumping two-phase gas-liquid mixtures. The model performance is compared with the models of Petrie et al.1 and Jiao et al.2; input data were the measurements taken by Jiao3 when testing an industrial HJP.
The present model results from the application of the one-dimensional conservation law of mass, momentum, and energy to the gas-liquid flow throughout the HJP. It differs from the previous published ones because it takes into account the flow of the two-phase compressible homogeneous mixture along the different parts of the device. It is not just an adaptation of a model originally developed for single-phase flows. Until now, most models representing the flow of a gas-liquid mixture in an HJP were adapted from models developed for incompressible single-phase flows. The gas compressibility, for instance, is fully considered, as was done by Cunningham4 when modeling a jet pump driven by a gas.
The solution of the proposed model requires the knowledge of two constant energy dissipation factors, i.e., flow inside the nozzle and flow inside the throat. The best values for these factors were obtained by performing a regression analysis over the data of Jiao.3 The results showed a consistently better agreement, over the full range of the operational variables, with the experimental data than those delivered by the existing models.
Stimulation for Methane-Gas Recovery From Coal
Authors: Jeffrey R. G. , Wold M. B. , Choi S. K. , Settari Antonin 
Published: December 2007

Summary
During the past several years, a combination of data from field and laboratory experiments, published data from commercial treatments, and concurrent analysis and model development activities has led to a better understanding of the processes occurring in coal during stimulation operations. At the same time, better modeling capabilities have been developed. For example, a new hydraulic fracture design model that includes pressure-dependent nonlinear leakoff, multiple interacting fractures, and failure in the coal near the fracture plane as a result of changes in effective stress is being developed and is being used to study fracture propagation in coal. In addition, two- and three-dimensional (2D and 3D) discrete element and hybrid finite element models that couple the mechanical and multiphase fluid response of the coal have been applied to analyzing problems arising from cavity completion operations.
In this paper, we compare data obtained from field trials in coal seams with model simulations, and we discuss the implications for stimulation design and execution.
Disproportionate Permeability Reduction Is Not a Panacea
Authors: Stavland Arne , Ekrann Steinar , Hettervik K. O. , Jakobsen S. R. , Schmidt Terje , Schilling Birgitte 
Published: December 2007

Summary
In this paper, we discuss experimental and theoretical studies on the effects of disproportionate permeability reduction (DPR) (i.e., the ability to reduce relative permeability to water more than to oil). The theoretical part discusses DPR effects by simple analytical arguments, supported by simulations. DPR causes buildup of water saturation in the treated zone to accommodate the water/oil ratio, Fwo, delivered by the reservoir. Core flooding experiments were also carried out, with a DPR gel placed in one half of the core. There is excellent agreement between theory and core flooding results. It was observed that the water saturation in the treated zone increased. Saturation profiles were measured with a CT scanner and is well matched by simulation.
Fast Procedure for Upscaling Compositional Simulation
Authors: Christie M. A. , Clifford P. J. 
Published: December 2007

Summary
Single-phase upscaling techniques have been in use for a number of years now to incorporate subgrid reservoir description information into reservoir simulation. There have also been a number of approaches to developing two-phase upscaling algorithms suitable for black oil simulation.
The key barrier to the development of compositional upscaling techniques is algorithm speed. A straightforward extension of existing two-phase upscaling approaches would consume enormous amounts of computer time because of the number of additional components modeled and the need to perform flash calculations.
This paper describes an upscaling method for simulations in which compositional processes play a key role, such as miscible gas injection or gas cycling schemes. We will describe the method to generate upscaled compositional fluxes in two or three dimensions, and the way in which the upscaled fluxes are incorporated into a compositional simulator.
Our approach uses a streamline technique, which provides a tremendous gain in speed for the loss of a small amount of accuracy. The streamline technique produces upscaled fluxes almost identical to those obtained from postprocessing conventional compositional model runs in a fraction of the time.
The results of applying these upscaled fluxes in a realistic example show that we can obtain close agreement between fine and coarse grid models of lean gas injection into oil at residual saturation. For an example problem with a 12-component equation of state (EOS), the component recovery curves with upscaled fluxes on a 5 × 5 grid agree well with the original 100 × 20 fine grid
Predicting Natural or Induced Fracture Azimuths From Shear-Wave Anisotropy
Authors: De G. S. , Winterstein D. F. , Johnson S. J. , Higgs W. G. , Xiao H. 
Published: December 2007

SummaryPrediction of fracture orientation to determine depletion geometry is a key step in reservoir characterization and development optimization. Wireline crossed-dipole anisotropy logs measure shear-wave velocity anisotropy and provide a relatively inexpensive alternative to tiltmeter surveys and nine-component vertical seismic profiles (9C VSP's) for such predictions. A multiwell study in Cymric oil field, California, was conducted to map the variations in the predicted azimuth of induced fractures in a shallow Miocene siliceous shale reservoir (&gt;500 millions of barrels of oil in place). Results from anisotropy data showed that the azimuths predicted by anisotropy logs and VSP's agreed. The agreement is significant because these two technologies measure very different kinds of seismic waves and have scales of investigation differing by two orders of magnitude. Within the productive zone, the predicted fracture azimuths from anisotropy data differed by about 60° from the regional stress in the NW portion of the Cymric development, while they were approximately aligned with the regional stress in the SE portion. Marked changes in azimuth also occurred as a function of depth across a regional Plio-Miocene (P-M) unconformity.Independent evidence, including observed steam breakthrough, natural fracture azimuths, and curvature analysis, supports the azimuths predicted from anisotropy data. Time-lapse temperature data from observation wells in a pilot steamflood showed anisotropy in horizontal permeability. Microresistivity borehole imaging logs allowed measurements of borehole breakouts and large, open natural fractures. The curvature analysis indicated a NW trending region of high curvature in the NW part of the Cymric structure.The large changes in azimuth with both depth and location in the development area show that regional stress maps are inadequate for planning oilfield development when stress patterns are complex, especially when deviated wells or induced fracturing are planned. Local stress configurations, therefore, must also be determined.
Analysis of Surface and Wellbore Hydraulics Provides Key to Efficient Blowout Control
Authors: Oudeman Pieter 
Published: December 2007

Summary
Assessment of blowout rate and composition is a key issue for decisions concerning blowout control method, design of kill operations, determination of direct (e.g., environmental) and indirect (loss of reserves) damage, etc. Usually, loss of control over the outflow of the well implies that the blowout rate cannot be established with conventional means. Experience shows that, because of the large reservoir decompression, production well performance cannot be extrapolated reliably to blowout conditions. Hence, surface (simple) observations, such as wellhead/drillpipe pressure and temperature, effluent shape and size and noise field, results of previous kill attempts, and pressure response of nearby wells have to be interpreted in terms of the blowout rate. This paper presents two examples of blowouts for which the combination of such data led to a consistent and accurate picture of blowout well performance; it also describes how such estimates contributed to decisions concerning the kill strategy, leading to success in a relatively short time.
A Review of Zechstein Drilling Issues
Authors: Williamson M. D. , Murray S. J. , Hamilton T. A. P. , Copland M. A. 
Published: December 2007

Summary
A number of issues can arise when drilling through Zechstein formations that have a bearing on the health and safety of personnel, as well as on the time to complete operations and final well costs. Operational problems present some intrinsic hazard or safety risk. Additionally, the procedures applied to alleviate these problems also present a safety risk, as they are usually nonroutine and unfamiliar, thus increasing the likelihood of errors.
In this paper, the operational issues, their causative mechanisms, and alleviation procedures are introduced and categorized. Decision analysis is applied to each of the operational issues, for both the well planning stage and for the drillsite, which relates the well responses to the causative mechanism and, therefore, to the selection of the most appropriate alleviation procedure.
Field Cases of Cost-Efficient Slickline Well Interventions
Authors: Larimore D. R. , Fehrmann G. Z. 
Published: December 2007

Summary
The comparison of today's slickline capabilities with its early usage for routine remedial workovers and maintenance best illustrates the significant advances that have occurred within slickline technology. Today, for example, slickline can be used to set and retrieve slickline-retrievable safety valves or plugs; open and close downhole circulating devices; retrieve accurate depth/time data for correlation with memory production surveys for well diagnostics (problem identification), reservoir description, or flow analysis; provide accurate correlation of tubing casing collars; and pull and run multiple flow controls, set packers, and other downhole equipment without explosives, set monobore tools, and perform other well interventions that are dependent on measurement accuracy. This expansion is overwhelming when considering that less than a decade ago slickline was considered only for mechanical well workovers.
This paper discusses the newly developed technology that allows slickline to economically provide alternatives economically to services that were traditionally reserved for more costly options. Case histories illustrate the enlarged scope of services and how the equipment combines to provide the innovative low cost service options that the industry has been seeking.
Effect of No-Flow Boundaries on Viscous Fingering in Porous Media of Large Aspect Ratio
Authors: Yang Zhengming , Yortsos Yanis C. 
Published: December 2007

SummaryWe report on a boundary effect associated with the preferential propagation of viscous fingers along no-flow boundaries in miscible displacements in two-dimensional (2D) rectilinear geometries near conditions of transverse equilibrium (TE) (large values of the generalized aspect ratio RL). It is shown that this effect intensifies with an increase in the mobility ratio, and diminishes with increased permeability disorder, and as the system departs from conditions of TE. The effect disappears altogether if periodic boundary conditions are used. We show that this effect results from the violation of the no-slip condition at no-flow boundaries, associated with Darcy's law. It must be considered in simulations of viscous fingering in relatively homogeneous media, near conditions of TE, particularly when gravity segregation occurs.