bluuebunny/crossref_metadata_2025_split huggingface dataset:
Downhole Fluid-Loss Measurements From Drilling Fluid and Cement Slurries
Authors: Haberman J.P. , Delestatius M. , Hines D.G. , Daccord G. , Baret J-F. 
Published: December 2007

Summary
This paper reports on a cooperative effort to demonstrate that direct field measurements of the fluid loss from wells are possible and yield significant results. Four wells in the Mississippi River delta were systematically shut in, and the fluid loss from the annulus was measured both with only mud in the annulus and after cement placement. The wells had extensive intervals of permeable sands, making them well-suited for fluid-loss tests. The results indicated a much lower fluid loss per unit area of permeable sands both before and after cementing compared with routine laboratory testing. Results also indicated that cement fluid loss was controlled mainly by filtration properties of the drilling-fluid mudcake.

Introduction
One fundamental requirement for a successful cementing job is the complete displacement of drilling mud during cement placement. Means to achieve this include conditioning the drilling mud and using preflushes, casing movement, and centralizers. These procedures displace the mobile mud and, if applied aggressively, most of the gelled mud.
The effect of these procedures on the drilling-mud filter cake has caused controversy in the industry for many years. Laboratory studies have shown that mudcake is difficult to erode, and when it is partially removed by the tangential flow, the filtration rate is not modified. However, when turbulent spacers displace the mud at high rates or when mechanical scratchers are used, filtration rates can increase significantly.
A fundamental question has been whether mudcake maintains its integrity and low permeability sufficiently during the cementing process to control the fluid loss from cement slurries or whether the filtration properties of cement slurries control the overall fluid loss. All the results before this work were obtained by laboratory testing or computer simulations and had not been compared with actual field fluid-loss measurements. The objectives of this project were to measure in the field fluid loss from the annuli of wells before and after the casing was cemented, to answer some of the questions raised, and to develop measurement techniques that could be used for further studies.
Downhole fluid loss (DHFL) was measured (after the intermediate casing was run) by closing in the casing annulus with the annular blowout preventer (BOP) and pumping water into the annulus through the surface casing valves. Measurements were made several ways to obtain the maximum value from the results.To determine the accuracy of the measurements, the DHFL measured by a pressure-decline method was compared with the DHFL measured by a fluid-injection method.To determine the effect of cement placement on the mudcake, the DHFL before cementing was compared with the DHFL after cementing.To determine the effect of cement fluid-loss-control additives, the DHFL with additives in the cement slurries was compared with the DHFL without additives.
Advancements in Dynamic Kill Calculations for Blowout Wells
Authors: Kouba G. E. , MacDougall G. R. , Schumacher B. W. 
Published: December 2007

SummaryThis paper addresses the development, interpretation, and use of dynamic kill equations. To this end, three simple calculation techniques are developed for determining the minimum dynamic kill rate. Two techniques contain only single-phase calculations and are independent of reservoir inflow performance. Despite these limitations, these two methods are useful for bracketing the minimum flow rates necessary to kill a blowing well. For the third technique, a simplified mechanistic multiphase-flow model is used to determine a most-probable minimum kill rate.
Experimental Data Analysis of Lost-Circulation Problems During Drilling With Oil-Based Mud
Authors: Onyia E. C. 
Published: December 2007

Summary
This paper presents interpretative analyses of experimental data from a joint industry project that investigated the phenomenon of lost circulation during drilling with high-density oil-based muds. These experimental results provide a better understanding of the mechanics of the oil-based-mud lost-circulation phenomenon and solutions to this problem.
Total Computer Simulation of a Gas Producing Complex
Authors: Cooksey Robert A. , Henderson James H. , Dempsey John R. 
Published: December 2007

An ADI computer model is used to match the pressure-production history of a gas reservoir. Tied to this model is a steady-state model that, by locating energy sources and sinks, can help to determine the optimum investment scheme for a given gas gathering system.

Introduction
An accurate prediction of reservoir performance is of prime importance for all gas reservoirs. Equally prime importance for all gas reservoirs. Equally important is the ability to optimize investments and still obtain good reservoir performance. Failure to give proper consideration to investment factors will diminish the economic attractiveness of the reservoir. In addition, reservoir performance can be altered drastically by the flow facilities wells, flowlines, compressors that are available to produce and process gas. Adequate flow facilities must be present to permit good reservoir performance.
Application of reservoir simulators to the study of reservoir behavior and investment planning is gaining a widespread appeal. An earlier paper by Henderson, Dempsey and Tyler discusses how well placement and reservoir operational strategy can be optimized by analysis with a reservoir simulator. In the present study the problem of investment planning is approached at a different level. This paper shows that required flow facilities can be optimized if the reservoir behavior can be predicted under various conditions.
Rather than an idealized condition deigned to fit a reservoir model, this study is an actual field case history using observed and predicted data for a particular reservoir. particular reservoir. The location and amount of compression along a gathering line is determined for a certain reservoir production rate. Compressor stations are located at production rate. Compressor stations are located at various points on the gathering line. Also, consideration is given to various production rate schemes of certain poor gas wells in an effort to reduce the amount of poor gas wells in an effort to reduce the amount of compression necessary to operate the field. The reservoir performance was predicted using a two-dimensional single-phase simulator based on Eq. 1.
(1)
The gas gathering system predictions were solved using the well known Weymouth equation for flow of gas in a pipeline. The reservoir model is described in dear in Ref. 4.

Statement of Problem
This study was conducted on a dry gas sandstone reservoir containing 25 wells. The planned total reservoir withdrawal rate is shown in Fig. 1. The gathering system consists of a variety of pipelines linked together in a normal fashion and connected to a single downstream outlet (Fig, 4). Compression currently is installed at the downstream end of the gathering system, located at Site A. Earlier expectations indicated that additional compression would be located at the same station. This plan necessitates that gas from all wells in the gathering system be compressed.
JPT
P. 942
Development of Miscibility in Four-Component CO2 Floods
Authors: Orr F. M. , Johns R. T. , Dindoruk Birol 
Published: December 2007

Summary
A rigorous tie-line extension criterion for the minimum miscibility pressure (MMP) is derived for dispersion-free, 1D displacements in four-component systems in which CO2 displaces oil containing dissolved methane. The key tie-lines required for application of the MMP criterion are obtained by a simple graphical construction. A simplified technique for construction of solutions is demonstrated for the CO2/methane/butane/decane system. The new technique makes solution of certain four-component problems not much more difficult than solution of a Buckley-Leverett displacement of oil by water.
Effects of Reservoir Anaerobic, Reducing Conditions on Surfactant Retention in Chemical Flooding
Authors: Wang F. H. L. 
Published: December 2007

Summary
Surfactant retentions observed in four microemulsion-flooding pilot tests at the Loudon field were substantially lower than predicted from conventional laboratory coreflood experiments. This paper presents research results that explain this discrepancy. The oil reservoir was in an anaerobic, reducing condition, whereas laboratory corefloods were normally conducted under aerobic, oxidizing conditions. The difference in redox condition was shown to have a serious effect on surfactant retention. Laboratory corefloods conducted under reservoir-like, anaerobic, reducing conditions gave surfactant retention results significantly closer to those observed in field tests. The effect of redox conditions on surfactant adsorption was substantiated further by results from static adsorption experiments with various clay types. Exposure of preserved cores from a reduced reservoir to aerobic conditions can cause high surfactant retention in corefloods. Methods were developed to restore such oxygen-contaminated core material to its original, anaerobic, reduced state. These coreflood procedures simulate actual reservoir conditions better and give meaningful surfactant-retention results for process design optimization.
CO2 Flow Patterns Under Multiphase Flow: Heterogeneous Field-Scale Conditions
Authors: Chang Yih-Bor , Lim M. T. , Pope G. A. , Sepehrnoori K. 
Published: December 2007

SummaryA finite-difference, equation-of-state (EOS), compositional simulator has been used to study CO2 flooding. First, unstable first-contact-miscible (FCM) displacements were simulated with a fine mesh to investigate the transition from gravity override to viscous fingering. Next, a direct comparison was made for FCM and multiple-contact-miscible (MCM) displacements under the same conditions to investigate effects of phase behavior on the growth of viscous fingers. Then, the effects of gravity, physical dispersion, capillary pressure, phase behavior, and heterogeneity were combined and simulated for CO2 flooding on a field scale with stochastic permeability fields.
Rock Characterization in Reservoirs Targeted for Horizontal Drilling
Authors: Skopec R.A. 
Published: December 2007

Summary
Achieving the maximum economic benefit from horizontal drilling requires thorough understanding of reservoir characteristics. The direct measurement of rock properties from oriented core is critical in horizontal-wellbore design. This paper outlines the measures and testing necessary to evaluate naturally fractured reservoirs effectively with field and laboratory technologies. Rock mechanical properties, fracture strike, and principal in-situ stress magnitudes and directions should be known before a horizontal wellbore is drilled. These data can then be used to maximize the intersection of natural fractures and to minimize the potential of borehole failure. In exploration wells, a vertical pilot hole must first be drilled. The zone of interest is cored, field tests are performed, laboratory testing is completed, and the reservoir is evaluated. With this information available, decisions can be made to optimize the borehole azimuth and well placement. We have used this approach to formation evaluation in several reservoirs where rock characterization is essential in the exploration and drilling program.

Introduction
Since 1985, the oil and gas industry has experienced an enormous increase in horizontal drilling. In preparation for drilling a horizontal well, a number of existing technologies can be used to increase the chances for a successful exploration program. Oryx Energy Co. has effectively used vertical-pilot-hole oriented coring, rock characterization, and openhole small-volume hydraulic fracturing to evaluate formations targeted for horizontal completions. These methods are particularly useful in exploration wells with little or no available data. This approach also allows timely evaluation of the reservoir before the horizontal well section is drilled. First, the well is drilled vertically (Fig. 1) to the zone(s) of interest, and microfracture tests are performed to determine the in-situ stress magnitude. Oriented cores are taken to measure the in-situ stress direction, and mechanical tests are done to determine the rock failure criteria. These data must be included in the design of the horizontal section of the wellbore a priori to achieve favorable results. The well can then be plugged back and kicked off horizontally in the optimum direction determined by the analytical program.
Predicting Depletion Behavior of Condensates
Authors: Farley R.W. , Weinaug C.F. , Wolfe J.F. 
Published: December 2007

Abstract
A rapid, accurate method for predicting the dew points of gas condensate systems and their points of gas condensate systems and their subsequent normal and retrograde phase behavior with pressure decline has been developed. The method predicts dewpoint pressure, volume percent liquid, condensate content of produced gas, and the liquid and gas compositions at pressures below the dewpoint pressure. Use of a modified form of the BWR equation of state, which was established by regression calculations on experimental data from several gas condensate, provides depletion behavior predictions that are significantly improved over predictions that are significantly improved over predictions using K-values based on convergence predictions using K-values based on convergence pressures and Standing's correlation for density.

Introduction
Prediction of complex hydrocarbon-mixture thermodynamics is fundamental to reservoir and gas precess engineering. In particular, accurate precess engineering. In particular, accurate descriptions of phase behavior are needed to plan production operations for gas-condensate reservoirs. production operations for gas-condensate reservoirs. Although analysis of reservoir behavior during producing and cycling operations can be made for producing and cycling operations can be made for simple reservoir models, extensions of these studies to more complex reservoir systems are still difficult, both with regard to numerical techniques and the phase behavior of the fluids. This report presents phase behavior of the fluids. This report presents a mathematical method for handling the complex phase relationships encountered in retrograde phase relationships encountered in retrograde condensates; it represents an advance in reservoir behavior technology in that it will aid the development of closed-form mathematical representations of total production systems.
A typical phase diagram for a complex hydrocarbon mixture is shown in Fig. 1. When the reservoir temperature Tr is higher than the critical temperature Tc and lower than the critical-condensation temperature Tct, the mixture is a gas condensate. Decreasing the pressure on a condensate while maintaining nearly constant temperature will result in two phases forming at the dew point. Further decrease in pressure will cause additional liquids to be formed. This phenomenon is called retrograde condensation. As pressure continues to decrease, normal phase behavior regions are encountered (liquid vaporizes as the pressure decreases) until the low-pressure dew point is encountered.
When a gas-condensate reservoir is produced, gas is withdrawn and the volume of fluids in the reservoir remains nearly constant as the pressure declines. heavier components tend to accumulate in the liquid phase as a result of retrograde condensation, while lighter components tend to concentrate in the vapor phase.
An Equation of State for Condensate Fluids
Authors: Kennedy Harvey T. , Bhagia NANIK S. 
Published: December 2007

Abstract
An equation of state has been developed for determining the molal volumes of both liquids and vapors of pure hydrocarbons from methane through hexanes. It is also applicable to nitrogen, hydrogen sulfide and carbon dioxide. A modification of the equation has been formulated specifically for application to condensate reservoir fluids.
The equation is of the same form as that proposed by Redlich and Kwong. However, a and b proposed by Redlich and Kwong. However, a and b are functions of temperature instead of being constants of each material. The equation as applied to pure gases and liquids, has an average absolute deviation from experimental values of 0.16 percent and 0.18 percent, respectively. As applied to 4,465 data points on condensate reservoir fluids, with temperatures to 322 degrees F and pressures to 15,500 psi, the average deviation was pressures to 15,500 psi, the average deviation was 1.48 percent. The equation compares favorably with other published works.

Introduction
Many equations of state for hydrocarbons have become available in recent years. One might question the need for further research effort in this direction. We feel this work is justified because it:
- has provided greater accuracy over extended ranges of provided greater accuracy over extended ranges of both temperature and pressure;
- has been applied to about six times as many data points as the previously most useful equation; and (3) is simpler previously most useful equation; and
- is simpler than any other equation that approaches its accuracy.
The equation was developed primarily to predict the volumes of mixtures of gases under high pressure in condensate reservoirs. We found it gave the simplest and most accurate means of estimating the volumes of pure hydrocarbon gases, using the same constants for the individual components. When a set of constants and the appropriate root were selected for least error as applied to pure hydrocarbon liquids, the most favorable equation for this purpose resulted.
Other similar methods have been proposed.
Special Considerations for Electric Submersible Pump Applications in Underpressured Reservoirs
Authors: Powers Maston L. 
Published: December 2007

Summary
This paper investigates the effect of electric submersible pump (ESP) performance tolerances and minor speed variations on the producing rate of wells completed in underpressured reservoirs, and presents ESP design considerations unique for this class of wells. These wells require considerable head to initiate flow and have relatively flat well-load curves. Pumps that operate near their maximum recommended rate have steep performance curves, and this is shown to minimize the effect of an underperforming pump on producing rate. Equations are developed for calculating the effects of pump performance and speed. Application requires evaluating the slopes of the pump-performance and well-load curves at design rate. The usefulness of these equations is demonstrated by practical examples. It is also demonstrated that flow stall can occur easily in underpressured reservoir applications when pumps designed to operate near their minimum recommended rate are installed.
Design and Diagnosis of Deviated Rod-Pumped Wells
Authors: Gibbs S.G. 
Published: December 2007

Summary
A wave equation method is presented for the design of deviated rod-pumped wells. Applications made to wells involve bare rods, molded-on guides, and wheel-rod guides. The design method is also used to explain the type of errors that result when vertical-hole techniques are used to compute down hole pump cards in crooked wells.

Introduction
Commonly used methods for designing rod-pumping installations presume vertical wells. This paper introduces a wave equation methodology that applies to deviated wells, whether they are deviated intentionally or unintentionally. Restrictions on surface locations and interest in horizontal drilling are increasing the need for deviated wells. Together with long-standing crooked-hole problems, these are promising subjects for further study.
This paper describes a predictive method that applies to 3D problems. A well deemed too crooked to pump is studied, and a procedure for designing intentionally deviated wells is presented. The relative friction effects of rod guides are discussed, and the effect of borehole path on power consumption is treated. The concept of dogleg severity is examined and deemed inadequate as a measure of difficulty in pumping deviated wells. The types of errors that result when vertical-hole diagnostic methods are applied to deviated holes are discussed. Finally, a new formulation of the radius-of-curvature concept is derived together with techniques for deducing rod-tubing friction from dynamometer valve checks. Comparisons with actual measurements are included to validate the methods.
Deviated wells can be adequately designed with wave equation methods, and highly deviated wells can be produced with rod-pumping equipment when care is taken to control the path of the borehole. This paper should be considered as a progress report because much remains to be learned about the application of this technology.
Gravel Placement in Wells
Authors: Penberthy W.L. , Echols E.E. 
Published: December 2007

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Summary
Several gravel-placement techniques are available to the engineer for prepacking and gravel packing wells where sand control is required. Both water and viscous fluids have been used effectively to prepack gravel outside the perforations; however, when gravel packing the annulus, the advantages and disadvantages of each fluid become more apparent. Research and field experience has shown that water is a more general-purpose transport fluid for gravel packing than are viscous fluids. The latter are best suited for low well deviations and relatively short completion intervals.

Introduction
Gravel packing wells has proven to be a viable completion technique to exclude formation sand from produced fluids. The state-of-the-art has steadily improved during the past few years to the point that in certain oil and gas producing regions, the majority of the wells are gravel packed. Gravel packing involves the placement of accurately-sized gravel packing involves the placement of accurately-sized gravel around a screen or slotted liner in a well to form a downhole filter that will prevent the entry of formation sand into the well, yet allow the flow of formation fluids. Gravel packs can be performed either in open-hole intervals or inside perforated casing (cased-hole gravelpacks), but the usual choice is the latter. The primary reason for this selection is that fewer complications are encountered with drilling and completion operations. However, there are also reservoir and workover considerations Open-hole gravel packs are selected when drilling, completion, and reservoir conditions are ideal. Since such conditions seldom prevail, cased-hole gravel packs have been the usual choice.
Experience and Evaluation of Production Through High-Rate Gravel-Packed Oil Wells, Gullfaks Field, North Sea
Authors: Unneland Trond , Waage R. I. 
Published: December 2007

Summary
This paper presents field data and performance analysis for high-rate gravel-packed oil wells in the Gullfaks field. More than 2 years' worth of production history is available for the earliest gravel-packed wells. From extensive production testing and reservoir monitoring, the initial performance and performance history before water breakthrough was evaluated. An addendum reviewing later developments (1991-1993) is also included.