bluuebunny/crossref_metadata_2025_split huggingface dataset:
Behavior of Oil Muds During Drilling Operations
Authors: Galate J. W. , Mitchell R. F. 
Published: December 2007

Summary
This paper presents an analysis of the behavior of diesel-oil-based muds with an advanced thermal and hydraulic wellbore mathematical simulator. Recent diesel-oil-mud rheological correlations have been incorporated into the model to account for viscosity and density variations of oil mud with temperature and pressure. As rheological correlations are developed for other oil-based muds, such as mineral-oil-based muds, they can also be incorporated into the model.
A specific deep-well application of the model illustrates the behavior of oil-based muds and shows the differences between water-based mud and oil-mud local fluid densities during drilling, circulating, and static conditions. Temperature and density profiles are presented for various operating conditions to show that modeling improves the understanding of oil-mud behavior downhole.
Decline-Curve Analysis Using type Curves—Case Histories
Authors: Fetkovich M. J. , Vienot M. E. , Bradley M. D. , Kiesow U. G. 
Published: December 2007

SummaryCase-history studies demonstrate methods of analyzing rate-time data to determine reservoir variables and to predict future production, Constant-wellbore-pressure analysis techniques use existing qdD-tdD type curves and new qdD-tdD type curves from actual field data.
Utility of Motor-Speed Measurements in Pumping-Well Analysis and Control
Authors: Gibbs S. G. 
Published: December 2007

Summary
This paper describes how motor speed can be used to deduce operating conditions in rod-pumped wells. Through the use of motor performance data, speed can be used to infer gearbox torque, unit balance, motor load, qualitative dynamometer cards, and power consumption. Pumpoff control and continuous monitoring are also applications of the methods discussed.
Two Bottom-Hole Pressure Instruments Providing Automatic Surface Recording
Authors: Kolb R.H. 
Published: December 2007

Introduction
A long term project at Shell Development Co.'s Exploration and Production Research Laboratory has been the improvement of the accuracy and the ease of BHP measurements. As a result of these efforts, two complete and separate systems have now been built for the automatic logging of BHP variations. The first of these is a small-diameter instrument suitable for running through production tubing on a single-conductor well cable. During the development of this instrument, as much emphasis was placed on providing a high degree of usable sensitivity and repeatable accuracy as on obtaining the advantages of surface recording. The second system combines the benefits of automatic, unattended recording with the convenience of a permanently installed Maihak BHP transmitter.

The Cable Instrument
For many years the standard instrument for BHP determination has been the wireline-operated Amerada recording pressure gauge or one of several other similar devices. This gauge records on a small clock-driven chart carried within the instrument, and although relatively precise readings from the chart are possible, they are difficult to obtain. Both the maximum recording time and the resolution of the time measurements are limited by chart size, and when a slow clock is required for long tests, the precision of the time measurement is often inadequate. Since it is impossible to determine the data being recorded until the gauge has been returned to the surface, wasted time often results when a test is protracted beyond the necessary time or when it is terminated too soon and must be re-run. Clock stoppage or other malfunctions which would be immediately apparent with surface recording remains undetected with downhole recording; the test is continued for its full term with a consequent loss in production time. As new uses for subsurface pressure data evolved, the shortcomings of the wireline instrument became increasingly apparent, and the concurrent development of a surface-recording pressure gauge and the associated high-pressure well cable service unit was undertaken.
Effect of Aquifer Size on the Performance of Partial Waterdrive Gas Reservoirs
Authors: Al-Hashim H. S. , Bass D. M. 
Published: December 2007

Summary
Predicting the advancement of a gas/water contact (GWC) in a waterdrive gas reservoir plays an important role in evaluating, forecasting, and analyzing the reservoir performance. This study was conducted to predict the behavior and the rise of the GWC, assuming that it remains horizontal, and to determine its effect on ultimate gas recovery. Several factors control the rise of the GWC. Some of the most important factors are the size of the aquifer, gas production rate, initial reservoir pressure, and formation permeability. These factors account for the abandonment of a number of gas reservoirs at extraordinarily high pressure.
Several methods have been developed for predicting the volume of water influx into a reservoir; the van Everdingen-Hurst method is used in this study. The performance calculated in this study was based on the material-balance equation for gas reservoirs. The gas reservoir pressure was adjusted to the original GWC for the water-influx equation, and the trapped gas in the water-invaded zone was accounted for in the water-invaded region. A constant reservoir permeability of 300 md was used in all calculations. The results showed that when ra/rg≤2, the effect of the aquifer on gas reservoir performance can be neglected. Also, the rate at which the GWC advances is controlled by the aquifer size when ra/rg &gt;2. Finally, regardless of the size of the reservoir, when ra/rg&gt;2, the pressure in the unsteady-state water-influx equation has to be corrected to the original GWC. Failure to do so may result in an error of more than 100% in the cumulative water influx, which in turn could lead to the wrong conclusions regarding the performance of the gas reservoir.
Automatic Determination of Lithology From Well Logs
Authors: Delfiner Pierre , Peyret Olivier , Serra Oberto 
Published: December 2007

Summary
A procedure combining modern wireline measurements with a lithofacies data base has been developed to produce an automatic lithologic description of the formations crossed by a well.
The database lithofacies are defined from petrographic knowledge and translated in terms of log responses. The assignment of depth levels to a lithofacies is done with the data base and with a discriminant function (Bayesian decision rule). External knowledge can be taken into account by use of artificial intelligence methods. A confidence factor is produced for each result.
Logs currently in the data base are the density, neutron, sonic transit time, gamma ray, photoelectric cross section, and concentrations of thorium, potassium, and uranium. Major lithofacies groups represented in the data base include sandstones, limestones, dolomites, shales, coals, and evaporites. These are subdivided by introducing cement and special minerals and by considering porosity ranges.
The construction of the data base is a critical step. It is largely empirical and requires careful calibration against intervals with well-known lithologies (e.g., from cores). The data base can be tuned to local conditions.
The procedure has been tested in several environments and compared with cores and mud log descriptions. A detailed lithologic column can be produced at the wellsite and used in decision making. The results can also serve as input for further geologic studies of facies and sequences or for quantitative evaluation of formations.
Estimating Reservoir Parameters From the Gas Backpressure Equation
Authors: Brlgham William E. 
Published: December 2007

Abstract
Although Eq. 2 is not quite exact, it is usually accurate enough for engineering purposes.
The question often arises whether Eqs. 1 and 2 can be related to each other. In particular, we would like to know whether the empirical constants C and n in Eq. 1 can be related to the reservoir parameters in Eq. 2. Such a relation is discussed in Ref. 2, but this narrative is not correct. In particular, Eq. 6.74 of that reference and the unnumbered equation at the top of Page 327 are both incorrect. This discussion shows how the constants in Eq. 1 can be related to reservoir parameters.
When one looks at Eq. 2 in detail, one finds that at a low flow rate, a graph of Δp2(Δp2=p¯2−pwf2) vs. qsc will have a slope of 1.0 on log-log paper, while as the flow rate increases, the data curve upward and the slope increases, so that at a high flow rate the slope is 2.0. This behavior is shown in Fig. 1, which is a reproduction of Fig. 6.45 of Ref. 2. Over the usual rather narrow range of well tests (e.g., for about 4 to 20 MMscf/D [0.1 × 106 to 0.57 × 106 std m3/d] in Fig. 1), the curvature is not great and a straight line (Eq. 1) will fit the data nearly as well. Thus it should be possible to relate Eqs. 1 and 2 by determining the conditions under which the slopes are the same. This is the basis used here to relate the constants in Eq. 1 with the reservoir parameters in Eq. 2.
Investment Evaluation by Present-Value Profile
Authors: Wooddy L.D. , Capshaw T.D. 
Published: December 2007

Introduction
There is a trend today for business enterprises to be more thorough in their approach toward making capital expenditure decisions. Correspondingly, there has developed a large volume of literature dealing with problems connected with the analysis of capital expenditure proposals or opportunities. Much of the literature describes methods of preparing economic data for analysis; recently, however, there have been many papers on the subject of measuring the worth of the investment opportunity. This paper deals with both areas. It attempts to describe methods useful to the analyst in presenting economic data to management. It is believed that these methods provide optimum utility for decision making. The paper also describes the limitations of the methods and the ways they might be viewed or interpreted by management in various financial positions.
The prosperity of the petroleum industry, perhaps as much or more than any other industry, is dependent on the efficient employment of its capital. This particularly is true in the producing end of the industry because a large part of its assets are continuously being depleted and must be replaced by additional capital expenditures. It has been estimated that capital expenditures for the domestic industry as a whole will exceed $7 billion during 1959, and that drilling and producing investments alone will amount to $4.5 billion. Thus, investments in producing and drilling operations will exceed $12 million daily, on the average. It is readily apparent that management is confronted with a tremendous job in making decisions on a vast number of investment opportunities.
Oil industry executives usually rely upon economic analyses prepared by staff groups, particularly geological and engineering staff groups. The economic analysis normally is based on engineering or geological studies of the particular venture, which are usually highly complicated and contain many assumptions. Assumptions are necessary when certain data are unavailable or for the inclusion of future aspects into the analysis, and these assumptions always result in a degree of risk. Management normally attempts to evaluate risk by understanding the mechanics of the technical study; however, the economic analysis, to be complete, should provide for the measurement of the risk factor as well as the profitability.
Liner Rotation While Cementing: An Operator's Experience in South Texas
Authors: Arceneaux M. A. , Smith R. L. 
Published: December 2007

Summary
The literature is replete with papers emphasizing the use of pipe movement while cementing to improve the opportunity for a successful primary cement job. Most operators, however, are reluctant to use liner movement, either reciprocation or rotation, while cementing.
This paper reviews experiences with nine rotating liners in south Texas since Dec. 1983. The liner hanger system and procedure used in rotating while cementing is discussed. Mud types and weights, hole sizes vs. bit diameter, cement slurries and volumes, hole deviation, and torque encountered are reviewed. A postanalysis of each job, pressure and differential tests performed, and typical cement bond logs will be presented.
Good primary liner cementing minimizes problems in production and stimulations and reduces cost. Liners were rotated throughout cement displacement on 77% of the jobs, while rotation was initiated on 88%. Liner rotation while cementing has improved the cement jobs and reduced the remedial cement work.
Improved Interpretation of the Inaccessible Pore-Volume Phenomenon
Authors: Gilman J. R. , MacMillan D. J. 
Published: December 2007

Summary
In laboratory corefloods, polymer solutions used in EOR, such as partially hydrolyzed polyacrylamides (PHPA), often break through at less than 1 PV injected compared to the breakthrough of pure water. The rapid breakthrough is erroneously used to determine the ratio of pores accessible to polymer to total PV (accessible PV). Through numerical simulation and steady-state analysis, we show that the rapid breakthrough of such polymer solutions is not a measure of accessible PV. The only thing that can be inferred from the polymer solution breakthrough time is that polymer solution travels faster than water. Breakthrough time depends on the injected polymer concentration and shear rate.
Our results significantly affect interpretation of polymer flow in porous media. Laboratory-measured polymer bulk properties are not those that should be used in conventional reservoir simulation and pressure-transient test analysis of polymer solutions.
We show two different forms of the same partial differential equation used to describe rapid polymer breakthrough. The finite-difference solutions lead to two different polymer concentrations for each gridblock—a flowing concentration and a bulk (volume-average) concentration. The polymer-concentration-dependent properties required for each formulation must be interpreted correctly.
Application of Preconditioned Conjugate-Gradient-Like Methods in Reservoir Simulation
Authors: Northrup Elizabeth J. , Woo Pang T. 
Published: December 2007

Summary
Conjugate-gradient-like (CGL) methods were used to solve the matrix equations for several large-field and fine-grid models. The methods used incomplete LU (ILU) or modified incomplete LU (MILU) preconditioning coupled with orthomin acceleration. The CGL methods were applied to the original matrix or to a reduced system from red/black ordering. Test results from a black-oil model with fault throws, a fractured reservoir model, and three steamflood models are given. It was found that the CGL methods are effective for solving the matrix equations. A more powerful preconditioner improves reliability but may require more work. Guidelines for selecting the most effective method are provided.
Controlling Effects in Countercurrent Two-Phase Flow
Authors: Johnston A. J. 
Published: December 2007

Summary
In many two-phase-flow situations, the prediction of conditions likely to instigate the change in flow regime from stratified to slug is important because this change or "choking" of a pipe may dictate the maximum flow rates possible in that pipe. This paper considers the appropriate parameters in the development of a suitable stability criterion for this transition in countercurrent flow. This criterion is then quantified with the results from an experimental test rig. Finally, a typical two-phase petrochemical situation is examined by use of this stability criterion, and the produced results are compared with previous stratified-flow predictions to identify the controlling effect.
Rapid, High-Temperature, Field Test Method for Evaluation of Geothermal Calcium Carbonate Scale Inhibitors
Authors: Asperger R. G. 
Published: December 2007

SummaryA new test method is described that allows the rapid field testing of calcium carbonate scale inhibitors at 500° F [260 °C]. The method evolved from use of a full-flow test loop on a well with a mass flow rate of about 1×106 lbm/hr [126 kg/s]. It is a simple, effective way to evaluate the effectiveness of inhibitors under field conditions.Five commercial formulations were chosen for field evaluation on the basis of nonflowing, laboratory screening tests at 500°F [260°C]. Four of these formulations from different suppliers controlled calcium carbonate scale deposition as measured by the test method. Two of these could dislodge recently deposited scale that had not age-hardened. Performance-profile diagrams, which were measured for these four effective inhibitors, show the concentration interrelationship between brine calcium and inhibitor concentrations at which the formulations will and will not stop scale formation in the test apparatus. With these diagrams, one formulation was chosen for testing on the full-flow brine line. The composition was tested for 6 weeks and showed a dramatic decrease in the sealing occurring at the flow-control valve. This scaling was about to force a shutdown of a major, long-term flow test being done for reservoir economic evaluations. The inhibitor stopped the scaling, and the test was performed without interruption.
Effect of Isolated Vertical Fractures Existing in the Reservoir On Fluid Displacement Response
Authors: Givens J.W. , Crawford Paul B. 
Published: December 2007

Abstract
A potentiometric model study has been made of the effect of vertical fractures existing in the matrix of the reservoir on the flooding or cycling performance. Fractures can have unusual flow characteristics. Fluid entering one side of a fracture can emerge on either the same or opposite side of the fracture, depending on the particular streamline. Fracture orientation has a great influence on the sweep efficiency. However, sustained fluid injection may still permit large areas to be swept.
Introduction
One can find considerable information available in the literature on the effect of fractures originating at the wellbore on sweep efficiencies of waterflooding or gas cycling programs. However, there are few, if any, quantitative data reported in the literature on the effect of vertical or horizontal fractures existing out in the reservoir matrix on secondary recovery performance. Several papers have been presented on the effect of vertical and horizontal fractures on the productivity or conductivity of waterflood and gas injection patterns, but in all cases the fractures initiated at the well and simulated commercial fractures. It is believed that natural fractures may exist out in the reservoir matrix and would effect the displacement performance. The purpose of this report was to study the effect of a few isolated vertical fractures existing out in the reservoir matrix on the performance of waterflood or gas injection patterns.
DESCRIPTION AND EQUIPMENT
Since the potentiometric model was described by Lee it has been widely used to study numerous types of fluid displacement problems. The potentiometric model can be used for fluid displacement studies when the following assumptions are valid:
(a) steady-state conditions exist; (b) the mobility ratio is one; and (c) the capillary and gravitational effects can be neglected.
Five-spot and direct line drive square patterns were studied using a copper strip of the desired length and orientation to simulate a vertical fracture in the reservoir matrix. The 20 x 20-in. model was considered to represent only one element of an infinite array of similar patterns.
DISCUSSION AND RESULTS
FIVE-SPOT PATTERN ONE FRACTURE BETWEEN INJECTION AND PRODUCING WELLS
Fig. 1 shows a quadrant of a five-spot pattern with the vertical fracture existing out in the matrix along a line connecting the injection and producing wells. Length of the fracture was equal to 35.4 per cent of the distance between injection and producing wells. In this particular pattern it is noted that fluid breaks through from the injection well to the producing well when the dimensionless time is equivalent to 26.9. Dimensionless time is defined as volume of fluid injected divided by the volume of displaceable fluid in the pattern expressed as a per cent.
SPEJ
P. 81ˆ
Biocide Evaluation Against Sessile Xanthan Polymer-Degrading Bacteria
Authors: O'Leary W. B. , Boivin J. W. , Dasinger B. L. , Beck D. , Goldman I. M. , Wernau W. C. 
Published: December 2007

Summary
This paper supports the use of formaldehyde at economically feasible concentrations as a biocide for EOR processes that use xanthan biopolymer. Its biocidal action against anaerobic sessile xanthan-degrading field organisms was clearly superior to three other biocides tested when 100% kill was used as the criterion for effectiveness.
Automated and Manual Methods for the Determination of Polyacrylamide and Other Anionic Polymers
Authors: Allison J. D. , Wimberly J. W. , Ely T. L. 
Published: December 2007

Summary
The concentration of Polyacrylamides is determined by precipitation with Hyamine® 1622 Reagent 1 and by measurement of the amount of light scattered by the resulting turbidity. The analysis can be automated as well as adapted for field trials. The effects of anionic surfactants, changes in Polyacrylamide molecular weight, and salinity are discussed.
Improving Polymer Injectivity at West Coyote Field, California
Authors: Shuler P. J. , Kuehne D. L. , Uhl J. T. , Walkup G. W. 
Published: December 2007

Summary
This paper presents a case history where laboratory and simulation results were used to model a single-well polymer injectivity field test in the West Coyote field and to improve injectivity in a subsequent field test. The polyacrylamide used in the first test exhibited low injectivity. Laboratory studies were performed to identify the causes of low injectivity and to model the field test physically. Laboratory core data and reservoir properties were used in a mathematical model to calculate the polymer injectivity, which closely matched that observed in the field.
The low polymer injectivity at West Coyote was a result of formation damage caused by the polymer and low-salinity polymer makeup water and the high resistance factor developed by the polymer. These problems were overcome by using a lower-molecular-weight polyacrylamide, preshearing the polymer solution before injection, and increasing the salinity of the polymer makeup water. These improvements resulted in a 50% increase in injectivity during the second polymer injectivity field test at West Coyote.
Water-Influx Modeling of the Svartsengi Geothermal Field, Iceland
Authors: Gudmundsson J. S. , Olsen G. 
Published: December 2007

SummaryIn this paper, lumped-parameter models are presented for confined and unconfined liquid-dominated geothermal reservoirs without recharge and compared to production data from the Svartsengi geothermal field in Iceland. They show that recharge or water influx is likely to affect the field's drawdown with time. Three petroleum reservoir water-influx methods.are then presented for steady-state, pseudosteady-state, and unsteady-state aquifers encroaching into the geothermal reservoir. History matching shows that the reservoir/aquifer system is best described as unsteady state and radial, with the aquifer boundary taken at infinite distance.