bluuebunny/crossref_metadata_2025 huggingface dataset:
The Importance of Petrophysical and Geochemical Data in Oil Recovery Studies
Authors: Rousselet Daniel C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The part played by petrophysical and lithological characteristics in recovery studies is well-known to all petroleum engineers. However, we found that physics-chemical and geochemical data e.g. physics-chemical and geochemical data e.g. oil composition, natural surfactant concentration, proportion of organic materials included in the matrix, are also to be carefully considered. They concern water-oil and fluid-matrix interactions, which influence the static equilibrium between oil and water in fields as well as microscopic displacement flow during waterfloods.

Some examples concerning fields operated by ELF-RE in foreign countries are presented, they provide a better understanding of the conditions provide a better understanding of the conditions necessary for an efficient waterflood, which include in particular :–Anomalous saturation distribution, which can be explained by palynology.–High water production from carbonatedfields, even when the in situ oil saturation measured seems high.–Low oil recovery during waterflood, which is ascribed to a high organic sediment content in the porous medium.–Reduced imbibition due to high concentration in kerogene and carbonates.

1 –

Introduction

All persons working on mechanics concede that Darcy's equation conveys globally, and with accuracy, the isotherm flow of a Newtonian fluid; this fluid, whose composition assumed to be constant, circulates at low velocity in a permeable medium of uniform composition, without any physico-chemical reaction as regards to the fluid, other than liquid-solid adhesion.

This equation also gives a satisfactory insight in the following cases :–polyphasic flow of immiscible liquids by extension of Darcy's law)–flow of miscible fluids with diffusion–convection phenomena
Interpretation of Horizontal-Well Production Logs: Influence of Logging Tool
Authors: Ozkan E. , Sarica C. , Haci M.
Published: December 2007

This paper investigates the influence of production-logging tool on wellbore flow-rate and pressure measurements. The focus of the investigation is on the disturbance caused by the production-logging tool and the coiled tubing on the original flow conditions in the wellbore. An analytical model is used in the investigation and single-phase liquid flow is assumed. The influence of the production-logging tool on the measurements is substantiated by the deviation from the original flow-rate and pressure profiles. It is shown that the influence of the production-logging tool manifests itself in low-conductivity wellbores. High production rates further amplify the effect of the production-logging tool. It is concluded that the effect of the production-logging tool may be ignored if dimensionless well conductivity exceeds 500 and the Reynolds number is lower than 100000. Results indicate that a production log run in a low-conductivity horizontal well may not indicate the low-permeability zones along the well.
Evaluation and Prediction of the Performance of Positive Displacement Motor (PDM)
Authors: Li J. , Tudor R. , Ginzburg L. , Robello G. , Xu H. , Grigor C.
Published: December 2007

Positive displacement motor (PDM) has been used extensively in the drilling operation. Motor performance is essential to ensure drilling success. In the traditional way, the performance of a PDM can be described by pressure drop versus torque and the rotational speed. For a particular type of motor, the RPM curves are different at different flow rates. Due to the limited test results, the performance of the motor can not be fully described. The prediction of the motor performance is very important for both motor design and operation. In this paper, analysis of the test results of PDMs collected using various PDMs from different PDM suppliers and the different correlations developed to describe the motor performance pumped with incompressible drilling fluid are discussed.
Modelling Scale Inhibitor Squeeze Treatments in High Crossflow Horizontal Wells
Authors: Mackay E. J. , Sorbie K. S.
Published: December 2007

Modelling scale inhibitor treatments in horizontal wells is emerging as an important field of research due to the need to reduce the cost of treating wells that may be thousands of feet long. Simulation studies performed using recently developed modelling tools have led to recommendations that have reduced the risk of chemical upsets at the wellhead and extended squeeze lifetimes downhole.

However, as an increasing number of "problem wells," such as high crossflow wells, need be treated to prevent scale formation, these models have to be adapted to enable them to capture the complex range of properties that make these systems so problematic. Diverter technology is being developed to enable optimal placement of chemical inhibitor, but to study the impact of the diverter on the squeeze performance, the fluid flow properties in the near-wellbore region must be modelled accurately. This is done by using a full-field reservoir simulation model that includes sufficient detail in the near-well formation not only to capture the fluid flows, but also to model accurately the chemical placement and recovery. The model can assess the impact of various placement strategies, as well as assist in determining the optimal fluid and chemical volumes.

A case study from the North Sea where a gel diverter was selected to assist inhibitor placement is presented. The study demonstrates the types of calculation that can be made, and what information can be usefully supplied to the field engineer designing squeeze treatments.
Experimental Study on the Productivity of Complex Well Configurations
Authors: Yildiz Turhan , Deniz Ozer
Published: December 2007

This study presents experimental results for the productivities of complex well configurations. The experimental study covers the productivity measurement for selectively completed vertical wells, horizontal wells with multiple flow entries, duallaterals, multilaterals including chicken-foot well configuration, perforated wells, and hydraulically-fractured horizontal wells. Inasmuch as an analogy exists between electrical and fluid flow, an electrolytic analog apparatus was constructed to perform the experiments. The apparatus was basically composed of a 100×100×50-cm Plexiglas tank, a variable voltage source, and several ammeters and voltmeters.

Experimental results were used to verify the analytical productivity models. In all cases, excellent agreement was established between the experimental and analytically calculated productivity values.

The experimental data presented in this study is very useful for engineers and researchers to verify their analytical productivity models and the computer codes.
Unusual Logs in an Unusual Formation: NMR in Athel Silicilyte
Authors: Looyestijn W. J. , Alixant JL , Hofman J. P.
Published: December 2007

The log evaluation of an expelling source rock is notoriously challenging because the kerogen and the generated oil coexist in the source rock. The Athel silicilyte is both an overpressured light-oil reservoir and a world-class source rock. In this unique geological setting found in the South Oman Salt Basin, reservoir characterisation is intimately associated with source rock evaluation.

In the absence of any direct geological analogue, the initial petrophysical model was calibrated against extensive core analyses. Porosity interpretation was then based exclusively on wireline bulk density measurements. The limitations of this approach only became apparent as attempts to reconcile data from various sources failed. While efforts aimed at obtaining representative core material and establishing reliable core analysis procedures, in-situ calibration of the petrophysical model was also actively pursued. NMR logging was primarily introduced to reduce uncertainties affecting density-derived porosities in the presence of variable, unknown organic matter content.

The first NMR log run in a silicilyte well could not be fully reconciled with density data. Laboratory NMR confirmed the log measurements, but more questions were raised when significant NMR signal was recorded on dry, cleaned samples at the time when new field data could not be explained.

Athel silicilyte is unique, and with no reference to confirm or to invalidate new data and interpretation, consistency and integration are key to improving our understanding of the rock. A thorough review of NMR acquisition procedures and processing algorithms was undertaken with logging contractors; job planning was improved, new logging procedures were implemented, tool malfunctions were identified and remedied, processing methods were upgraded. Laboratory procedures were revisited, and NMR core measurements were complemented with additional, independent core analyses.

Whereas the initial emphasis was on "effective" porosity determination, NMR logs and core measurements provided new insight into the Athel silicilyte rock. This includes: (i) strong indications that the rock may be mixed-wet; (ii) encouraging results in the area of permeability estimation; and (iii) indeed higher confidence in the assessment of effective porosity. A TOC (Total Organic Carbon) log can also be derived, which could find further application in source rock evaluation and the characterisation of organic-rich reservoirs. Integration of all available log data using a statistical approach now provides a consistent reservoir description, with limited core calibration requirements. Having successfully integrated NMR data to unravel the organic content of the rock, the improved petrophysical model provides the basis for sound reservoir characterisation, the foundation for better exploration, appraisal and development decisions.
Dirty Sand Consolidation Technology for Gas Wells
Authors: Cobianco S. , Lezzi A. , Massara E. Previde , Pitoni E.
Published: December 2007

Italian gas fields are usually composed of many sand layers, which must be produced separately: therefore, multiple completions are very common in Italy. Shallower layers, the most prone to produce sand, are completed with sand control techniques: open hole gravel pack and inside casing gravel pack installed above fracturing pressure (frac pack)1–3 are the most popular completions. Sometimes shallower layers can not be completed in sand control just because the uppermost selective gravel pack on short string was installed in a deeper, more prolific, sand layers. Conventional completion (without sand control) is the only possible technique applicable in these layers.

Formation sand can not be consolidated with standard chemical treatments (e.g. resins) because of the high clay content (25–50%) and the low permeability (10–200 mD). The use of frac pack with resin coated proppant is not allowed by the thin thickness of sand layers where the fracture can extend toward close water layers. A novel sand consolidation technique especially suited for prevention of dirty sand influx in gas wells has been developed. Laboratory testing of the new sand-control system gives a minimum 70–80% permeability retention and the resulting compressive strength is sufficient for an effective sand control. The cementing materials, as shown by SEM (Scanning Electron Microscopy), can be described in terms of precipitation of amorphous silica and migration of clays.

This paper reports the laboratory testing and results: the novel system is able to consolidate very low dirty permeable sands (< 1 mD) containing high concentration of clays (up to 50%) and carbonate materials (up to 20%)

This technology has been employed in field trials with positive results.
Slaying the Myth of Infinite Reactivity of Carbonates
Authors: Gdanski Rick , Van Domelen Mary S.
Published: December 2007

The simplifying assumption that limestones essentially have infinite reactivity has been a powerful and useful tool in helping our industry understand and model the acidizing process of carbonate formations. However, over the past few years, considerable work has shown that this assumption need not be used. In fact, use of this assumption can lead to incorrect conclusions regarding optimized acidizing of carbonate formations. This paper builds upon the historical foundation of understanding the acidizing process and brings together the reactivity studies using a number of different reactors to show that carbonates do not have infinite reactivity. It also shows the results of using proper reactivity data and proper reactivity theory for treatment designs.
Alba Northern Platform-Produced Water System Improvements
Authors: Turnbull David
Published: December 2007

The Alba Field is operated by Chevron UK Ltd and located in the central North Sea. It came on stream in January 1994. As water production levels increased, it became progressively more difficult to maintain the oil in water overboard figure below the statutory requirement of 40 ppm. Process investigations included a full system fluids characterisation study which identified a mean oil droplet size of 8–10 micron in the produced water. The original platform design assumed a larger oil in water droplet size and this low value produced a correspondingly low removal efficiency from the existing produced water hydrocyclone facility. Initial side stream trials led to the development and installation of a 20 tonne ‘interim’ produced water polishing vessel to enhance the existing facilities for oil in water separation. A Computational Fluid Dynamics programme was utilised to model fluid flow in the new vessel and support the planned design of a full size vessel with the capability of treating 390,000 BWPD (3 times the present produced water rate) to fully meet the platforms predicted needs. A programme of specific chemical product screening singled out a newly developed dithiocarbamate chemistry as being highly effective in meeting the demands of limited chemical contact time and the short vessel residence time available. This combined chemistry and engineering design approach resulted in the platform meeting the 40 ppm oil in water discharge specification and thus avoiding the serious threat that continued non conformance posed to the current high oil production rates.

This paper describes the essential stages of this work and discusses the results and remedial action taken from the initial investigation through to the successful resolution of this problem. The paper content presents this from both an engineering and chemical treatment perspective.
An Empirical Correlation Between Reservoir Temperature and the Concentration of Hydrogen Sulfide
Authors: Håland Kjersti , Barrufet Maria A. , Rønningsen Hans P. , Meisingset Knut K.
Published: December 2007

The problem addressed in this paper was to establish an empirical correlation between the H2S concentration in reservoir fluids and the reservoir temperature. The work is based on data from a large number of exploration wells drilled in sandstone reservoirs on the Norwegian continental shelf. It is shown that with few exceptions, the H2S concentration in the produced fluid is close to zero, when the reservoir temperature is below a threshold temperature of about 220°F (105°C). Above this threshold, an exponential temperature dependency is shown to exist.

The empirical correlations developed in this work allow a reasonably accurate estimate of the expected H2S in produced gas. They are considered of particular importance for early planning of H2S control strategies and production management, especially in cases where only wireline formation tests have been conducted.
Oil Production, Past Commitments, and Increasing Returns
Authors: Heitmann George
Published: December 2007

Heitmann, George The Pennsylvania State University and the Ruhr-Universitt Bochum

The proposition that the oil industry operates under conditions of increasing costs is fundamentally correct, but must be properly qualified. In circumstances where complete input variability cannot be assumed, the "burden of the past" can impose constraints on investment decision alternatives such that demand induced increases in production will be achieved under decreasing cost conditions.

One of the recurring "myths" in the oil industry is the proposition that production takes place under conditions of proposition that production takes place under conditions of increasing returns (i.e., decreasing costs). As Adelman has put it: "this vision of decreasing costs and natural monopoly in oil is held clear across the political spectrum," to which he immediately adds, "perhaps it is just as well - or perhaps very bad - that we must reject the one opinion that seems common to all". That the oil industry is not a natural monopoly is fundamentally correct; however, there are some sound reasons for believing that incremental costs may indeed decrease over certain relevant ranges of production increase. The purpose of this paper is to outline some of the circumstances that will result in increasing returns. Part I summarizes the cost consideration associated with crude oil production, and particularly examines the development cost concept. In Part II the critical distinction between the short and long run is examined, and the nature of the decreasing returns argument is outlined. Part III introduces and appraises conditions under which increasing Part III introduces and appraises conditions under which increasing returns can be expected, and suggests that "myth" properly interpreted, may be reality.An oil field, to produce oil, must first be discovered and equipped for production.
Test and Research on the Commingled Development of Two Kinds of Low Efficiency Oil Reservoirs
Authors: Chao Huaqing , Fang Baocai , Pang Yanming , Xu Yunting , An Cheng
Published: December 2007

The interzonal interference of the commingled production of Putouhua and Fuyu oil reservoirs with large vertical distance (about 400m) and large permeability difference (air permeability of 118 X 10 -3 m 2 for Putouhua oil reservoir, 1.16 X 10 -3 m 2 for Fuyu oil reservoir) is solved, by theoretical analysis and field pilot test based on seepage mechanics. After one-year field pilot test, the production situation of each oil reservoir of the commingled reservoirs is coincident with the situation of single-reservoir production a line. These make the best use of the production capacities of these two oil reservoirs and provide experience and technology for economically and effectively developing the large overlaping area of Putouhua and Fuyu oil reservoirs in future.

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Coal's Increasing Role in the Fossil Fuel Industry
Authors: Eckard William E.
Published: December 2007

Coal was used by man thousands of years ago and has played a significant role in modern civilization. The solid fuel will surely continue to be important in the affairs of man. The United States has about 20 percent of the world's coal resources, enough to last several centuries even at an expanded rate of consumption. Projected expansion of coal consumption for energy and fuels production will require the solution of several major problems, including those related to mining methods, mine health and safety, economics, and coal process technology.

Introduction

The "energy crisis" of the 1970's, oddly enough, stems largely from a domestic shortage of petroleum, the so-called "rock-oil" that was discovered and came to our rescue back in the 1850's and 1860's. This saved us from the country's first energy crisis, "The Great Whale Oil Shortage" of the last century. Now, it looks like another energy source, coal, will be "discovered" and save us from the current shortage of essential fuels.

Let us think about coal for a few minutes-its history, availability, mining, and its potential as a future source of liquid and gaseous fuels.

History of Coal Use

The history of coal is rather fascinating and probably not very well known, even in the coal areas of the United States. No one knows when coal was first used, but it was believed to have been used for funeral pyres in Wales about 4,000 years ago. Coal may also have been used by the Chinese approximately 3,000 years ago, is mentioned in the Bible, and was known by the Greeks.

Coal was once considered a nasty, dangerous substance. The smoke and odor of burning coal frightened people; some though it was a curse. Laws were even passed to prohibit its use. History seems to be partly repeating itself, judging by current concern over pollution from coal mining and utilization.

Great Britain first fully recognized the true value of coal. Starting in the mid-1700's, coal began to serve as a source of power for steam engines, in effect, catalyzing the Industrial Revolution. Much of the coal used at that time was first converted to charcoal and. was referred to as "cole". Around 1900, the spelling was changed to "coal".

French explorers were the first to discover coal in North America. This was in 1679 near what is now Chicago, Ill. American Indians had made objects from coal before that time, however, and had used it in pottery-making in the Southwest.
The Economics of Coal Conversion Systems
Authors: Wellman Paul , Katell Sidney
Published: December 2007

Various systems are being considered for converting coal to either liquid or gaseous fuels. The economics of several of these systerns have been completed. Data are presented here for two of the most promising systems developed by the Federal promising systems developed by the Federal Bureau of Mines—the Synthane process, which uses a fluidized gasification system to produce high-Btu gas, and the Synthoil process, produce high-Btu gas, and the Synthoil process, which produces low-sulfur heavy fuel oil.

Introduction

In the past, the United States has been fortunate in having large reserves of the three major fossil fuel energy sources—gas, oil, and coal. Now this has changed. Gas and oil sources have diminished while demand has increased. This is not true of coal, which still is our most abundant fuel. It is the only major fuel that can meet our country's energy needs through this century.

Since coal in its original form is usually dirty and difficult to transport, it has become necessary to convert it into a more desirable form. At this time, the energy situation in the United States is critical enough to justify intense efforts to develop coal conversion methods. Research and development by the Federal Bureau of Mines and the Office of Coal Research is being directed toward the study of several conversion processes.

Synthane gasification and Synthoil liquefaction are two of the most promising systems that have been considered. One advantage shared by both systems is that they use any kind of coal. Much of our coal, especially that which is near large marketing areas, is highly caking and unsuitable for most gasification processes. Synthane uses the caking coals directly as well as a wide range of other coals including lignite. The Synthoil process converts high-sulfur coals to clean fuel oil that contains low concentrations of sulfur and ash.

The Process Evaluation Group of the Bureau of Mines has recently completed cost studies of these two systems. This paper deals with the economics and the technology of these two approaches to coal conversion.

The Synthane plant was designed to produce 250 million standard cubic feet per produce 250 million standard cubic feet per day of high-Btu gas, which will be suitable for substitute natural gas (SNG). The Synthoil plant was designed to produce 108,394 barrels plant was designed to produce 108,394 barrels per stream-lay of low-sulfur, heavy oil, which per stream-lay of low-sulfur, heavy oil, which is intended for use as a boiler fuel.
Influence of Rock and Fluid Properties on Immiscible Fluid-Flow Behavior in Porous Media
Authors: Merliss F.E. , Doane J.D. , Rzasa M.J.
Published: December 2007

An investigation of immiscible flow behavior in porous material as affected by fluid properties and the solid material characteristics has been made consolidated and unconsolidated sands.

Production mechanisms analyzed were external, gas and water drives and solution gas drives. Flowing pressures up to 1,500 psi were used. The work indicates that variations exist in the flow behavior of such systems, and that relative permeabilities and relative permeability ratios are functions not only of fluid saturations, saturation histories, and the porous material geometry, but also fluid properties and solid material characteristics.

An approximate method of determination of relative permeabilities from external drive experimental data has been derived to correlate the variations encountered in flow behavior. It is based on viscous flow theory and allows the mathematical determination of a pressure profile [for constant pressure differential or constant flow rate experiments] for external gas and water drive systems. Any desired static pressure may be used in the experiment.

Porosities and permeabilities were studied by choosing models with a wide range of characteristics. The consolidated sands had porosities from 13 to 21 per cent, while for the unconsolidated sand the porosity was from 34 to 39 per cent. Permeability ranges varied from 1.5 to 300 md for consolidated material, and 7 to 20 darcies for the unconsolidated material. The models used varied in length from 16 cm to 77 1/2 cm, with diameters from 2.54 cm to 5.08 cm.

The unconsolidated sand was treated with a silicone material to make it oil-wet for the water drive experiments. In the gas drive experiments on these treated sands, the silicone material effectively increased the oil-solid adhesion tension.]

Capillary phenomena were investigated to determine their effect on flow behavior in various wettability systems.

Introduction

The amount of oil that can be recovered economically from a reservoir is dependent upon the fluid-flow relationships which exist for that particular reservoir. Laboratory experiments are performed to arrive at relative permeability relationships which are used to make predictions of recoveries from reservoirs. Effective use of relative permeability characteristics requires knowledge of what they are and what affects them.
Latest Developments in High Strength Tubular Products for H2S Service
Authors: Franceschina L.E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Heat treating facilities at the Tube Division of The Algoma Steel Corporation, Limited make use of a novel water quenching process which has made possible development process which has made possible development of the highest strength levels of tubular products currently available for use in products currently available for use in hydrogen sulphide environments.

Development of the quenching process, the present state of product development, and present state of product development, and research toward production of even higher strength levels, will be reviewed.

In hydrogen sulphide environments, high strength steel products are known to be susceptible to sulphide stress cracking. This phenomenon is generally believed to be caused when hydrogen atoms, evolved on the metal surface by a corrosion reaction, tend to enter the metal in the presence of hydrogen sulphide. This atomic hydrogen trapped in steels drastically reduces the ductility and causes the steel to crack. As H2S is often one of the components found in oil fields and as oil drilling activity has steadily been forced to regions requiring deeper wells, the demand for high strength H2S resistant tubular products has also been increasing.

Casing and Tubing Grade C-75 produced by using normalized and tempered steels to meet A.P.I. Standard 5AC was the first grade to be used for this application. There is now, however, much evidence from laboratory and field testing showing that a quenched and tempered martensitic microstructure is much superior in resisting H2S attack than the normalized and tempered-microstructure. Normalizing produces a mixed grain structure depending on the composition of the steel and the cooling rate. Quenching from the austentizing temperature produces martensite, a form which is under stress.
Optimizing Plunger Lift Operations in Oil and Gas Wells
Authors: Wiggins Michael L. , Nguyen Sean H. , Gasbarri Sandro
Published: December 2007

Many low volume oil and gas wells produce at suboptimum rates due to liquid loading. This situation is caused by an accumulation of liquids in the wellbore that creates additional backpressure on the reservoir and decreases production. Plunger lift is an artificial lift technique characterized by the use of reservoir energy stored in the gas phase which is used to lift liquids to the surface and has proven to enhance the performance of these wells. Unfortunately, the lack of a thorough understanding of plunger lift systems has often led to disappointing results in actual applications.

This paper presents a discussion of plunger lift and the dynamic interaction of the mechanical plunger lift system coupled with the reservoir behavior. In this study, a dynamic plunger lift simulator is used to investigate various operating scenarios for both oil and gas wells. Analysis of the results provides improved insight into the efficient operation of plunger lift systems.
Interpretation and Correlations of Clay Swelling Measurements
Authors: Civan Faruk
Published: December 2007

Analytical models for interpretation and correlation of the effects of clay swelling on the permeability and porosity of clayey porous rocks are developed and verified by experimental data. The parameters of the models, including the swelling rate constants, and terminal porosity and permeability that will be attained at saturation, are determined by correlating the experimental data with these models. This study reveals that swelling of clayey rocks is essentially controlled by absorption of water by a water-exposed surface hindered diffusion process and the swelling-dependent properties of clayey rocks vary proportionally with their values relative to their satu-ration limits and the water absorption rate. These models lead to proper means of correlating and representing clayey rock properties, and enhanced understanding of the relevant processes.
Effect of Viscosity on Downhole Gas Separation in a Rotary Gas Separator
Authors: Lackner G. , Doty D. R. , Shirazi S. A. , Schmidt Z.
Published: December 2007

Electrical submersible pump (ESP) installations are commonly used in the oil industry to aid the flow of fluids from the reservoir to the surface. As with any pump, the presence of free gas at the pump intake can adversely affect the operation of an ESP. One method of reducing the amount of free gas that the pump has to process is to install a rotary gas separator.

In this work, the effect of viscosity on the performance of the separator is investigated. New experimental data were gathered, covering a broad range of operational conditions in terms of pressures, liquid flow rates, gas-liquid ratios and rotational speeds. The experiments were conducted on a field scale experimental facility using a commercially available separator. The working fluids were water, two mineral oils and air. An existing mechanistic model (based on physical principles) that predicts the bottomhole gas separation efficiency in ESP installations, was then evaluated with the data. Based on this investigation, improvements were implemented in the model to better capture the influence of viscosity on the downhole gas separation process.

The results of the study indicate that there are two regions of separation efficiency that have a pronounced transition between them. One region in which the rotary gas separator is very effective (separation efficiencies between 80% and 100%), and the other in which it is not effective at all (separation efficiencies between 30% and 55%). The location of transition depends on the fluid physical properties, operational conditions and geometry of the separator. . The mechanistic model can predict this behavior, and agrees well with the data that are obtained during this investigation. Fluid viscosity, in the range of investigation (1 cp to 50 cp at 100 ºF), is found to have only little influence on gas separation efficiency. This may indicate that the effects of turbulence, at high rotational speed, dominate the behavior of the flow inside the separator.
Assessment of Matrix Acidizing Treatment Responses in Gulf of Mexico Wells
Authors: Zhu D. , Hill A. D. , Morgenthaler L. N.
Published: December 2007

A coherent approach for evaluating matrix stimulation consists of a series of steps. First, pre-treatment well performance data needs to be collected to estimate how severe the well is damaged, and based on the initial information, a treatment can be designed. Then during treatment, skin response should be monitored through pressure and flow rate measurement, to: 1) insure the treatment is performing as desired, and 2) collect data for post-treatment study. From this step, the design and the information about the reservoir used in the design can be confirmed. Generally, a matrix stimulation consists of more than one stage, especially when diversion is required. Post-treatment review and interpretation of skin evolution during each stage provides valuable information regarding causes of the skin responses. And finally, the post-treatment well performance data can be used to confirm the skin estimate obtained during the treatment.

We studied the effectiveness of seventeen matrix acidizing treatments in Gulf of Mexico sandstone reservoirs by evaluating the skin factor evolution during the treatments from the rate/pressure responses and by examining production performances after stimulation. For these wells, the skin factors at the end of the acid treatment derived from analysis of the rate and pressure during the treatment were compared with skins obtained from post-treatment production. The study showed that the combination of these methods of evaluation provided additional information about the success of the treatments. Characteristic examples presented in the paper illustrate such behavior as effective stimulation, efficient diversion, acid over-treatment, and proper (or inappropriate) acid selection.
Coral Creek Field Study: A Comprehensive Assessment of the Potential of High-Pressure Air Injection in a Mature Waterflood Project
Authors: Glandt C. A. , Pieterson R. , Dombrowski A. , Balzarini M. A.
Published: December 2007

Shell has been producing from the Cedar Creek Anticline (CCA), in the Williston Basin, southeastern Montana, for more than 40 years. Presently, most fields are mature waterfloods with production rates declining between 3% and 8% per year. The producing rocks are low-permeability, non-fractured, porous carbonates that leave waterflood residual oil saturations in the range of 30% to 40%. In order to arrest decline and increase ultimate recovery, a tertiary technology, High-Pressure Air Injection (HPAI), has been considered.

Coral Creek Field in the CCA currently produces around 1300 stb/d of oil from the Red River Formation. Due to its size and its relatively low water-cut of 70%, Coral Creek was regarded as an ideal candidate to test HPAI. HPAI is being utilized successfully after primary depletion in other fields in the Williston Basin.1,2,3 However, the technical and economic feasibility of tertiary applications is yet to be demonstrated. A comprehensive field study was undertaken as a prerequisite of such an endeavor.

This study integrates all of the geological and production information accumulated during the life of the field, in order to assess the technical viability of tertiary HPAI. The main finding is that under the assumptions of the study, HPAI will not only arrest the production decline, but also double waterflood reserves and current rates in about 5 years.
Field Application of After-Closure Analysis of Fracture Calibration Tests
Authors: Talley G. R. , Swindell T. M. , Waters G. A. , Nolte K. G.
Published: December 2007

This paper describes field examples of fracture optimization that are based on the after-closure pressure decline period following a proppant-free injection. The primary benefit from these applications is the determination of reservoir transmissibility that is central to specifying the fracture length and conductivity for optimizing field-development economics.

The transmissibility is obtained from the after-closure pseudo-radial flow period. In the examples this transmissibility is compared with that calculated from conventional well testing. In one example, the well-test derived fracture half length is compared to the optimized length predicted from a fracturing simulator. Simulated versus actual production results are also compared.

The after-fracture closure period of an unpropped fracture injection potentially contains the reservoir pseudo-linear flow and pseudo-radial flow periods. Analysis of the linear-flow period enhances the standard calibration analysis of the pre-closure period (i.e., mini-frac analysis). One enhancement is the potential determination of spurt loss that can not be obtained from the pre-closure decline because spurt loss ends as the fracture extension stops. Another enhancement is the reservoir behavior's perspective of closure time and fracture's length that permits validating the values of these parameters from the pre-closure analysis. This definition of length is obtained from combining the linear and radial flow analyses.

The field examples are for a moderate permeability, normally pressured, dry-gas Morrow sandstone reservoir located in Hemphill County of the Texas panhandle. The selected testing sequence, and synergy of information from independent pre-frac tests, are reviewed as well as operational and theoretical constraints. A logical application procedure is developed for general field use in similar environments.
Reservoir Management Using Production Data
Authors: Soeriawinata T. , Kelkar M.
Published: December 2007

This paper presents a methodology to effectively use the production data to improve the performance of the existing water flood. Using simple statistical procedures and method of superposition (e.g., one producing well could be affected by several injection wells), the injection wells which are affecting the production of oil and water from individual producing wells are determined. The connection or the lack of connection between injection and producing wells based on the previous step can be utilized in optimizing water flood process and in modeling the reservoir. The method is tested in a synthetic water flood field and in a mature water flood field in West Texas.
Aircraft-Mounted Forward-Looking InfraRed Sensor System for Leak Detection, Spill Response, and Wildlife Imaging on the North Slope of Alaska
Authors: Pierre Bruce St.
Published: December 2007

ARCO Alaska, Inc. (AAI) at the Kuparuk Oilfield on the North Slope of Alaska recently initiated the use of an airborne Forward-Looking InfraRed (FLIR) Sensor System to enhance environmental protection in the arctic. Oil flows from the ground into production pipelines with temperatures in excess of 100 degrees F. If a leak were to occur in a pipeline, between the outer pipe wall and the surrounding insulation, a FLIR should be able to detect the leak. The efficiency of the aircraft-mounted FLIR system allows for the entire Kuparuk field, with over 700 miles of pipeline, to be surveyed in less than three flight hours. Not only has the airborne FLIR unit proven its ability to be an effective tool in the surveying of pipelines for potential corrosion due to water-soaked insulation, but it is also very effective in imaging a spill site and returning pertinent information to an Incident Command Team for spill response. Finally, the FLIR systems have been used to image wildlife in their habitat when visual methods produce inconclusive results. Wildlife surveys of caribou and polar bears have been conducted using the aircraft FLIR systems at Kuparuk. The FLIR sensor system is an innovative technology proving to be a good tool to ensure pipeline integrity and enhance protection of a sensitive arctic environment.
Environmental Lessons Learned in Privatizing a Government Oil Field
Authors: Garrison E. Grant , Maillett Edward J.
Published: December 2007

In February, 1998, as mandated by Congress, the U.S. Department of Energy (DOE) completed the U.S. Government's largest divestiture ever, the sale of the Naval Petroleum Reserves Number 1 (NPR-1) in Kern County, California to Occidental Petroleum for $3.65 billion dollars. Before that sale could take place, under the National Environmental Policy Act and the California Environmental Quality Act, DOE had to examine the environmental impacts of the privatization and assess their severity. NPR-1 is the seventh largest oil field in the U.S. It contains habitat critical to a number of endangered species, as well as National Historic Register eligible cultural resources. Thus, the transfer from government to private operation had the potential to significantly impact the environment.

The paper will summarize the methodology and conclusions of DOE's Environmental Impact Statement/Environmental Impact Report on the differences between government and private development of NPR-1, which was prepared for the government by ICF Kaiser's Consulting Group. The paper will also summarize the government's conclusions on the expected environmental impacts of the differences in future development. The paper will summarize the mitigation measures that the government and the new owner agreed to adopt in order to reduce the expected environmental impacts of privatization. Included in this summarization will be a discussion of the unique terms and conditions for the protection of threatened and endangered species at NPR-1 required to be undertaken by the new owner. Finally the paper will draw possible lessons learned from the environmental analysis that might have implications for future private oil and gas operations on or near government owned lands.
Downhole Oil/Water Separators: An Emerging Produced Water Disposal Technology
Authors: Veil J. A. , Langhus B. G. , Belieu S.
Published: December 2007

The largest-volume waste stream associated with oil and gas production is produced water. Treatment and disposal of produced water represent significant costs for operators. A relatively new technology, downhole oil/water separators (DOWS), has been developed to reduce the cost of handling produced water. DOWS are devices that separate oil and gas from produced water at the bottom of the well and reinject some of the produced water into another formation or another horizon within the same formation, while the oil and gas are pumped to the surface. Since much of the produced water is not pumped to the surface, treated, and pumped from the surface back into a deep formation, the cost of handling produced water is greatly reduced. When DOWS are used, additional oil may be recovered as well. DOWS may also be referred to as DHOWS or as dual injection and lifting systems (DIALS). This paper summarizes the findings of a report on the technical, economic, and regulatory feasibility of DOWS technology that was funded by the U.S. Department of Energy and prepared by Argonne National Laboratory, CH2M Hill, and the Nebraska Oil and Gas Conservation Commission.1
New Environmental Options for Corrosion Inhibitor Intensifiers
Authors: Brezinski M. M.
Published: December 2007

Common acid corrosion inhibitors frequently require the addition of intensifiers or contact time extenders when used in very strong acids, high temperatures, or for long contact times. Effective metal intensifiers have the severe disadvantage of being exceedingly toxic to aquatic life as well as humans. Copper salts are lethal to aquatic species at concentrations below lOppm. Antimony salts can also cause heavy metal poisoning when used in the required concentration ranges for inhibitor intensification.

Results are presented showing that a combination of low toxicity intensifiers produces an unexpected synergy and highly effective corrosion inhibitor intensifier system. For example, the use of two common intensifiers can allow contact times of 4 hours to be achieved at 300°F in 28% HC1 on common oil field tubular goods. Intensifier systems will be presented that allow a lower toxicity option to be used in mineral acid systems (e.g., HC1, HC1/HF) on N80/L80 and chrome alloy tubing. These systems can allow an adequate corrosion protection to be achieved that, until recently, was only possible with copper or antimony-based intensifiers. These systems can also be applied at lower temperatures and can significantly reduce corrosion inhibitor concentration requirements.

This development can allow high temperature acidizing to be carried out in areas where the environmental impact of the stimulation fluid is of great concern. The new technology can also cause significant savings in fluid costs by reducing the quantities of the acid corrosion inhibitor (sometimes as great as a 50% reduction). This latter benefit should also translate to better stimulation treatments by reducing both inhibitor incompatibilities with the treatment fluids and producing zones.
Remediation Strategies for Soils Contaminated with Amine-Based Gas Sweetening Wastes
Authors: Sorensen J. A. , Gallagher J. R. , Chollak D. , Harju J. A.
Published: December 2007

In the past, amine-based waste materials (i.e., reclaimer sludges and filters) generated by the natural gas sweetening process were occasionally disposed of into unlined pits. Such disposal of these waste materials often resulted in contamination of the subsurface soils.

Contaminants of concern associated with gas sweetening wastes include the amines used during the gas sweetening process (most commonly, monoethanolamine, diethanolamine, methyldiethanolamine, and diisopropanolamine), thermal/oxidative reaction products (typically, nitrogenous organic compounds), ammonia, and nonionic surfactants (i.e., nonoxynol and oleyl alcohols) typically used as antifoaming agents. Laboratory and field-based research activities conducted from 1993 to 1999 provided previously unavailable insights regarding the subsurface environmental behavior of gas sweetening wastes. The knowledge gained by those research activities has been applied toward the development of technically and economically feasible remediation strategies for contaminated soils. Based on the results of the research efforts, bioremediation methods such as engineered biopiles and land treatment cells may be the most technically and economically sound means of remediating soils contaminated with amine-based gas sweetening wastes. In 1998, a pilot-scale engineered biopile was built to evaluate the effectiveness of that technology for remediating amine sludge-contaminated soil at a decommissioned gas sweetening facility in Alberta, Canada.