bluuebunny/crossref_metadata_2025 huggingface dataset:
Some Effects of Pressure on Oil-Shale Retorting
Authors: Bae J.H.
Published: December 2007

A series of batch-type retorting experiments 930 degrees F were performed to investigate the effect of pressure and surrounding atmosphere on the retorting of oil shale. The experimental pressure ranged from atmospheric to 2,500 psig. pressure ranged from atmospheric to 2,500 psig. The sweeping gases used were N2, COe, H2O, NH3 and H2.

We found that high pressure reduces the oil yield significantly and produces a larger volume of light hydrocarbon gases. The crude shale oil obtained at high pressure has higher aromaticity and a lower pour point than the low pressure material. The sulfur pour point than the low pressure material. The sulfur and nitrogen content in shale oil does not change significantly with increasing pressure.

The effect of sweeping gas is usually small. In general, gases which decompose to yield H2 increase the oil yield at high pressure. At atmospheric pressure there is no effect. The high oil yield with H2, pressure there is no effect. The high oil yield with H2, more than 100 percent of the Fischer Assay, reported on "hydrotorting" experiments was not observed in this work.

Introduction

The in-situ retorting of oil shale has attracted much interest because it obviates the troublesome problem in surface retorting of mining, crushing and problem in surface retorting of mining, crushing and handling a large quantity of oil shale. The cost of these operations in the surface retorting process amounts to more than half the total production cost of shale oil. From an economic point of view, the recovery of shale oil by in-situ methods is highly desirable

At present in--situ retorting is accomplished by combustion or hot gas injection, following conventional hydraulic fracturing. Explosive fracturing also has been studied. While these methods of fracturing are promising, there is still much uncertainty associated with them. On the other hand, even if an adequate mass permeability could be created, the high pressures encountered at depths of several thousand feet where oil shale commonly existwould certainly affect the thermal decomposition of oil shale.

Thomas has experimentally simulated the effects of overburden pressure on the physical and mechanical properties of oil shale during underground retorting. Allred and Nielson studied the effect of pressure in reverse combustion on the yield and pressure in reverse combustion on the yield and quality of oil produced. These results are fragmentary and are applicable only to reverse combustion. Grant reported an oil yield of 35 to 40 percent of the Fischer Assay was obtained in a laboratory forward combustion experiment at 500 psig.

We decided to investigate the effect of pressure on oil shale retorting because so little information was available on subjects. We sought to determine me effects of fluid pressure and surrounding atmosphere on the quantity and quality of products obtained from retorting oil slide. Results of a series of batch-type retorting experiments are reported.
Large-Scale Properties for Flow Through a Stratified Medium: Various Approaches
Authors: Azita Ahmadi , Alain Labastie , Michel Quintard
Published: December 2007

Published pseudofunction theories are compared with the large-scale averaging method in the quasistatic case by numerical simulations of two-phase flow in a stratified medium for different flow regimes. In some cases, the large-scale averaging gives results that are as satisfactory as those of more complicated and more expensive methods.
The Effect of Trapped Gas Saturation on Initial Oil-in-Place
Authors: Earlougher R.C.
Published: December 2007

This paper investigates the need for an adjustment to volumetric calculations for initial oil in place and residual oil after waterflooding to account for in-situ trapped gas in many reservoirs.

Introduction

In 1962, I was coauthor of a paper that presented a porosity adjustment factor to improve volumetric calculations of oil recovery by waterflooding. The adjustment results in a reduction of calculated oil in place (OIP). The paper described in detail the determination of the adjustment factor but did not include a conclusive reason why the adjustment was needed.

Earlier publications described a laboratory procedure for the flood pot test on fresh core samples and reported that (1) rotary cores from many shallow reservoirs were not flushed by the drilling water, (2) waterflood oil recovery was determined directly from the flood, pot test, (3) total liquid saturation, Sl for many reservoirs seldom exceeded 95% PV after a water throughput in excess of 100% PV, and (4) volumetric calculations using Sl and porosity usually provided a much better fit with actual waterflood performance. Trapped free gas, Sgt, dispersed throughout the oil reservoir would provide a reason for the correction.

Table 1 illustrates the effect of the adjustment for a reservoir with 30 % Swi, an oil FVF of 1.2, and 9% Sgt. Trapped gas results in a reduction of initial stock-tank OIP, a greater reduction of residual oil after primary recovery, and an even larger percent reduction after waterflooding.

Four years ago, I had the new experience of finding 25 % N2 in the associated gas from an oil reservoir in the Morrow sand while consulting with Medallion Petroleum Inc. This finding reminded me of the use of the PV correction factor and the possibility of trapped gas. Consultation with many peers failed to find one who "knowingly" had encountered nitrogen in an oil reservoir. Further investigation led to a U.S. Bureau of Mines publication that included gas analyses for more than 13,000 oil and gas wells in the U.S. for the years 1917 through 1985. This publication suggests that free nitrogen in associated gas is not uncommon.
Field-Applied Computerized Tracking System: A Practical Approach to On-Site Quality Control
Authors: Purvis D. L. , Novotny R. J. , Carlson B. T.
Published: December 2007

Automation and monitoring of modern hydraulic fracturing treatments demand a unique approach incorporating intelligent data acquisition and control equipment. This paper describes how a computerized system was applied to the task.

During a treatment, several operations are conducted concurrently. Concentrated gelling agents must be precisely proportioned with various additives to form a base gel. This base gel is then blended with sand, crosslinking agents, and breakers to form the slurry that is pumped into the formation. These operations dictate the metering, measuring, and controlling of many parameters simultaneously over several pieces of mobile equipment.

Multiple microprocessor-based control modules are used to perform this task. Each module interfaces with various transducers involved in a particular operation. The use and design of these control modules are outlined, as well as the transmission of information between the modules and the operations control computer. The hardware, software, and ergonomic aspects of the system are discussed. Finally, an additional engineering computer system is outlined, including its link to the central monitor. The presentation of information in a manner to facilitate quality control is discussed. Throughout this paper, emphasis is placed on the use of computer technology to simplify and improve data analysis and quality control.
PC-Based Quick__Look Graphical Postprocessing in Reservoir Simulation for Thermal Recovery
Authors: Baldwin J. O. , Wilcox G. G.
Published: December 2007

In reservoir management, use of numerical reservoir simulators is playing an increasing role in developing planning, completion design, operating policies, and surveillance. Computer models, both in-house and commercial, are being used in EOR projects with detailed reservoir description for better understanding of the physics of multiphase fluid flow through porous media, history matching field and/or well performance, performing case sensitivities for variations in operating policy, and optimizing pattern and well spacing. For reservoir simulation to reach its full potential, it must become a tool that practicing reservoir engineers use with a high level of confidence. The goal of this paper is to demonstrate graphical postprocessing of reservoir simulation output as a key part in the overall results analysis process and as a critical link in assisting reservoir engineers with limited simulation experience to make competent decisions regarding reservoir development and operation.
A Laboratory Study of Gravity Drainage in Fractured Systems Under Miscible Conditions
Authors: Thompson J.L. , Mungan N.
Published: December 2007

Laboratory displacement tests were performed to study oil recovery efficiency by gravity drainage in fractured systems under miscible conditions. The porous media used were cylindrical Berea and Blue porous media used were cylindrical Berea and Blue jacket sandstone cores containing a number of well-defined, artificially formed, vertical and subvertical fractures. Butane and Soltrol 130 were the two miscible fluids used. The purpose of the study was to examine the influences of the displacement rate, fracture density, fracture orientation, fracture permeability, matrix permeability, crossflow, core length and connate permeability, crossflow, core length and connate water on the oil recovery.

It was found that displacement rate, matrix permeability and the subvertical fractures affected permeability and the subvertical fractures affected oil recovery most. The critical flow rate, based on the matrix permeability, was found to be a significant factor in the process. For displacement rates below the critical flow rate, the oil recovery efficiency appeared to be unaffected by the density of the subvertical fractures. At the high displacement rates, the fracture density becomes important, with the recovery being the most efficient in the core having the greatest number of the subvertical fractures. The magnitude of the fracture permeability, the fracture orientation, the core permeability, the fracture orientation, the core length and the connate water have little effect on the oil recovery efficiency.

Introduction

Gravity drainage under miscible conditions from relatively thick reservoirs can be a very efficient recovery process, especially at low flow rates where the gravity forces are dominant and, consequently, the adverse viscous fingers associated with the unfavorable viscosity ratio are minimized or eliminated. Such a process might involve injection of an LPG or some solvent bank at the crest and then driving the bank with dry gas. For some favorable combination of reservoir temperature, pressure and oil composition, there may be no need to inject any solvent bank, since enrichment of the dry gas by the light ends of the crude creates an in-situ solvent bank.

Slobod and Howlett have studied the effects of gravity segregation in vertical unconsolidated porous media under miscible conditions in the porous media under miscible conditions in the laboratory. The main variables in their study were the viscosity ratio, the density differences and the rate of flow. In this study, the objective was to find the influence of fractures on gravity drainage under miscible conditions. A greater number of related variables were also studied.
Optimization of Horizontal Well Matrix Treatments
Authors: Economides M. J. , Frick T. P.
Published: December 2007

This paper presents an optimization method for the matrix stimulation of horizontal wells that may include the deliberate blanking of well segments. The lengths of these segments are balanced against the stimulation fluid volumetric coverage of the perforated segments. The stimulation and completion design is optimized through the use of the net present value (NPV) as an economic criterion.
Performance Analysis and Optimization of the Prudhoe Bay Miscible-Gas Project
Authors: McGuire P. L. , Stalkup F. I.
Published: December 2007

Because EOR oil response at Prudhoe Bay has been difficult to measure directly, a number of different types of field measurements have been made to evaluate the miscible-flood displacement efficiency. These measurements include water- and solvent-injection profiles, logging data from an observation well, and single-well tracer test (SWTT) data. Despite ambiguity in these data, the measurements support the simulation and laboratory data and generally indicate that the Prudhoe Bay Miscible Gas Project (PBMGP) is performing well. The most useful EOR surveillance data have been the separator-gas-sample database, with ≈4,000 compositional analyses. Separator flash analysis and allocation programs use this database to infer EOR performance on the basis of produced solvent. Reservoir mechanisms that adversely affect the EOR process efficiency have been identified. The project has exceeded initial expectations in terms of solvent retained within the reservoir, which has favorable implications for solvent sweep efficiency. Procedures have been developed to use the field and simulation data to determine how the solvent should be allocated to the existing patterns and when the project should be expanded into new areas. These procedures are designed to maximize the value of the PBMGP.
Computerized Drilling Control
Authors: Young F.S.
Published: December 2007

An on-site computer system to control bit weight and rotary speed has been developed and successfully installed on a South Louisiana well. Early field tests indicate that the system could be invaluable in reducing drilling costs.

Introduction

Previous laboratory and field experimentation has Previous laboratory and field experimentation has demonstrated the effect of several variables on drilling rate. These results have been incorporated into optimization theories for the purpose of reducing drilling cost.

Minimum-cost drilling theories rely on a combination of historical data and empirical prediction techniques for selecting optimum bit weight and rotary speed. Past solutions have required extensive use of computing equipment because of both the complexity of the mathematical formulations and the large number of parameters involved. Field attempts to apply these computed results have frequently failed because of the uncertainty of input data requirements.

Humble has developed an on-site computer system to control bit weight and rotary speed and thereby implement the concepts of minimum-cost drilling. This system can

perform short interval drilling rate tests for formation evaluation, use the results of these tests as input information to solve minimum-cost drilling formulas, and control bit weight and rotary speed in accordance with these computed solutions.

The purpose of this paper is to describe the computer control system and present results of initial field testing.

Theoretical Considerations

Minimum-cost drilling (MCD) requires a quantitative evaluation of the variables involved. Several forms of a basic mathematical model have been suggested. The relationships reported here form the basis for the solution programmed in this work. Four equations are used, expressing drilling rate, bit bearing wear, bit tooth wear, and cost.

A solution for minimum-cost drilling assuming constant bit weight and rotary speed over the entire bit life has been programmed for use in computing MCD schedules. This solution is subject to certain limiting assumptions such as those discussed by Graham et al.:

Drilling cost is the summation of bit cost, rotating cost, connection cost and hoisting cost. Diamond bits are excluded. Bit life is limited by either bearing failure or tooth wear, or by a combination of operational factors that make it cheaper to pull an incompletely consumed bit. Circulating hydraulics are adequate and do not limit drilling rate. Bit weight considerations exclude hole deviation. Drilling rate is a function of only bit weight, rotary speed, and degree of tooth dullness; that is, the effects of pressure, lithology, fluid property, hydraulics and drill string dynamics are ignored.

JPT

P. 483
Evaluation of Spotting Fluids in a Full-Scale Differential-Pressure Sticking Apparatus
Authors: Clark R. K. , Almquist S. G.
Published: December 2007

A full-scale differential-pressure simulator was used to evaluate spotting fluids in the laboratory. Tests at elevated temperature and pressure identified a variety of unweighted and weighted, oil and nonoil fluids that are able to free differentially stuck pipe. Some low-toxicity, water-based spotting fluids are effective and acceptable substitutes for the traditional oil-based systems.
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

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

This 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

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

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

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

A 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

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

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

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

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

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.

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

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.
Drilling and Production Practices To Mitigate Sucker Rod/Tubing Wear-Related Failures in Directional Wells
Authors: Matthews C. M. , Dunn L. J.
Published: December 2007

When the Lindberg heavy-oil field in Alberta was being developed in the early 1980's, frequent wear-related workovers were experienced in wells directionally drilled from central pads. Four operating companies collaborated with the Centre for Frontier Engineering Research (CFER) in a field study organized to investigate these failures and determine techniques to extend production equipment life. The study included monitoring of rod and tubing wear and production parameters in more than 50 directional wells. Results showed that wellbore configuration had a strong and consistent effect on the wear rates of downhole equipment in directional wells. It also was demonstrated that local curvature variations, which led to wear-related failures in several wells, could be attributed to drilling and surveying practices. This paper offers guidelines on wellbore geometry design to optimize the performance of mechanical lift systems and presents field-based results on the effectiveness of wear-reducing equipment. It also makes recommendations regarding an operational program designed to minimize wear-related failures. The development and application of a model capable of predicting rod loads and tubing wear in directional or horizontal wells also are described.
Fracture Tip and Critical Stress Intensity Factor of a Hydraulically Induced Fracture
Authors: Yew C. H. , Liu G. H.
Published: December 2007

By modeling the rock as an elastoplastic solid obeying the Drucker-Prager failure criterion, we have demonstrated that, if the dilatation produced in the plastic zone in front of the fracture tip is inhibited by its surrounding elastic material, the critical stress intensity factor, KIc, of the material can be higher than those obtained from standard laboratory tests. Using Geertsma's fracture model and including the dry zone in analysis, we also have demonstrated that, unless the fracture is very large, the fracture opening width is affected by the KIc. of the material.
NORM Contamination in the Petroleum Industry
Authors: Gray P.R.
Published: December 2007

Contamination of oil and gas facilities with naturally occurring radioactive materials (NORM) is widespread. Some contamination may be sufficiently severe that maintenance and other personnel may be exposed to hazardous concentrations. Contamination with radium is common in oil-production facilities, whereas contamination with radon and radon decay products is more prevalent in natural-gas production and processing facilities. Although largely unregulated until recently, U.S. states, notably Louisiana and Texas, have or are enacting legislation to control NORM contamination in the petroleum industry.

Introduction

NORM contamination can be expected at nearly every petroleum facility. Some of it can be sufficiently severe that maintenance and other personnel may be exposed to hazardous concentrations. In addition, the industry must comply with new regulations. Mississippi and Louisiana have enacted legislation to control NORM; Texas will have regulations early in 1993; and other states, as well as Canada, can be expected to have similar regulations shortly.

Two general types of common NORM contamination will be controlled by these regulations.Radium contamination of petroleum production facilities - specifically of pipe scale and sludge and scale in surface vessels. In addition, produced water may be radioactive from radium dissolved in underground water.Radon contamination of natural-gas production facilities. This includes contamination with the long-lived decay products of radon. Facilities that remove ethane and propane from natural-gas facilities are especially susceptible to NORM contamination.

Naturally occurring radionuclides are widespread in the environment. In many geologic formations, radium, radon, and other radioactive elements are associated with oil and gas. When oil and gas are produced, traces of these radioactive elements also are produced. When the formation water contains traces of radium (radium-226, a decay product of uranium, and radium-228 from thorium), scale in the production pipe can become radioactive, sometimes containing several thousand picocuries of radium per gram of scale. The radioactivity results when radium coprecipitates with barium and strontium sulfates in the scale formation.
Reservoir Description Detail Required To Predict Solvent and Water Saturations at an Observation Well
Authors: Stalkup F. I. , Crane S. D.
Published: December 2007

This paper describes the reservoir simulator analysis of an observation-well pilot test in the Prudhoe Bay miscible flood. It shows that 1-ft simulator layers and explicit representation of thin, discontinuous shales are required to predict solvent occurrences and log-derived water and solvent saturations at the observation well. The predictions show that solvent flows past the well in numerous tongues that are only a few feet thick.
Analysis of a Steam Drive Project, Inglewood Field, California
Authors: Blevins T.R. , Aseltine R.J. , Kirk R.S.
Published: December 2007

This is the first reported California field data on the vertical extent and residual oil saturation of the steam swept zone. Field-derived data on reservoir heat distribution support the published theoretical data.

The Inglewood field, discovered in 1924, occupies a faulted anticline along the Newport-Inglewood Fault System on the western edge of the Los Angeles basin (Fig. 1). The Upper Investment zone, UB sand, selected for this test is the shallowest producing reservoir in the field and lies about 1,000 ft below surface ( 650 subsea). The UB sand productive limit are defined by an updip sand pinchout, the Inglewood Fault, and by down-dip water.

The UB sand is 40 to 60 ft thick, consists of fine- to coarse-grain sand with occasional pebbles, ranges from soft to unconsolidated, is overlain by a thick siltstone section and has bottom water. The reservoir properties are shown in Table 1, and electric log characteristics in Fig. 2. The air permeability ranges from 3.3 to 14.3 darcies in the top 40 ft of the reservoir, and porosity averages 39 percent. The primary producing mechanism is pressure depletion with primary producing mechanism is pressure depletion with water encroachment. Oil in place at start of project was 1,930 bbl/acre-ft. The Investment zone oil is asphalt base, 14 degrees API gravity with an in-situ viscosity of 1,200 cp.

The high oil viscosity, low reservoir pressure, shallow depth and high oil saturation are all favorable for application of thermal recovery methods. Preliminary laboratory studies of steamflooding in Inglewood cores indicated that residual oil saturations of approximately 20 percent could be achieved with throughput of 1 PV of water converted to steam.

Chevron Oil Field Research Co. and Standard Oil Co. of California, WOI conducted the Investment zone lost to learn if the low laboratory residual saturations could be obtained in the field and to determine the oil displacement efficiency in the project area. The test was designed to obtain data on vertical and areal coverage, heat losses, and rate of steam front advance, and to evaluate producing problems associated with continuous steam injection.

Design Project Area Project Area Fig. 3 shows the steamflood pilot layout. It is an inverted six-spot containing 2.6 acres within the five first-line producing wells. The project area of the reservoir has essentially no dip. Injection Well 270 and Temperature Observation Wells 271, 272, 273 and 293, were newly drilled for the project. The location of Wells 304 and 304A, which were drilled specifically to obtain post-steam saturation, is also shown in Fig. 3.