bluuebunny/crossref_metadata_2025 huggingface dataset:
Controlled Composition Seeded Growth Kinetics of Calcium Carbonate
Authors: Tomson M.B. , Nancollas G.H. , Kazmierczak T.F.
Published: December 2007

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

A highly reproducible seeded crystal growth method is described for the study of calcium carbonate crystallization in which the solution composition is maintained constant by the potentiometrically controlled addition of reagents. This provides a system which closely models the conditions of precipitation and scale formation encountered in the precipitation and scale formation encountered in the field. Studies can be made over a range of supersaturation hitherto inaccessible by other methods. The experiments yield information about the mechanism of crystal growth and the influence of potential scale inhibitors upon the growth of the pure scale minerals and the formation of mixed scales.

The inhibitory effects of phosphate and a phosphonate both at micromolar and lower levels phosphonate both at micromolar and lower levels have been examined. Both markedly affect the calcium carbonate precipitation at concentrations as low as 10 molar.

Introduction

The precipitation and dissolution of carbonate minerals of divalent metal ions such as calcium carbonate (calcite and aragonite) and calcium magnesium carbonate (dolomite) are of considerable importance in a wide variety of fields such as limnology, oceanography and sedimentology. The crystal growth of calcium carbonate also has important applications in water purification technology. The concentration of calcium carbonate in many natural waters is equal to or greater than the saturation level and as a consequence, calcium carbonate precipitation and crystal growth takes place in water treatment and desalination place in water treatment and desalination facilities. The resulting scale formation on heat transfer surfaces during evaporative desalination may significantly increase the cost of potable water. Since the solubilities of the calcium carbonate polymorphs decrease with increasing temperature, polymorphs decrease with increasing temperature, the petroleum engineer also has to contend with carbonate scaling at the relatively high ambient temperatures down-hole.

Calcium carbonate has probably received the greatest attention in connection with its precipitation and dissolution in natural water systems. The reaction is very sensitive to the presence of magnesium ions which are normally present at relatively high concentrations. It has been reported that magnesium ions favor the formation of aragonite while markedly inhibiting the precipitation rate. precipitation rate.
Improvement of Waterflooding of a Heavy Crude Oil By Addition of Chemicals to the Injection Water
Authors: Okandan Ender
Published: December 2007

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

A laboratory study of applicability of chemical flooding to a heavy crude oil reservoir is presented. The contact angle behavior of oil-water-calcite system was investigated to see the effectiveness of several chemicals added to the injection water.

Displacement tests performed using two selected chemicals show an increase in recovery compared with plain waterflooding.

Introduction

In the literature, several surface-active agents are proposed and investigated for their effectiveness as chemical flooding agents. It has been observed that interfacial properties between crude oil and water, interactions between water, oil, and rock grain surfaces, and adsorption of surface-active chemicals are the prime factors that should be considered and controlled in the process.

It was reported half a century ago that effectiveness of waterflooding could be increased by the addition of chemicals that will cause low oil-water interfacial tensions. Until today, parameters like porosity, permeability, pore-size distribution, permeability, pore-size distribution, wettability conditions, interfacial properties, chemical selection, their adsorption, and chromatographic transport through porous media were investigated in order to understand how the mechanism by which chemical flooding will displace crude oil from pore spaces.

Comprehensive work has been done on the influence of interfacial tension on oil recovery after the 1950's. Among them, Reisberg and Doscher's work indicated oil recoveries reaching 90 and 100 percent with the use of surfactants that caused interfacial tensions less than 0.01 dyne/cm. Wagner and Leach's work indicates sigma less than 0.07 dyne/ cm causes increases in oil recovery in their system. Later, Taber showed theoretically and experimentally the dependence of recovery of residual oil on the Delta/L sigma factor. Recoveries reaching 100 percent were achieved when this ratio had much higher values than the critical value given as 2 to 5 Psi/ft dyne/cm for that system. It was recognized also in the same study that the contact angle, which is an indication of wetting conditions at solid-liquid interfaces, should be included in the ratio Delta P/L sigma. Different wetting conditions may exhibit different dependence of recovery on pressure gradient or flow rate.
Time Dependent Electrical Properties of Rock-Solution Systems
Authors: Weed H.C. , Piwinskii A.J. , Keller P.R.
Published: December 2007

The electrical conductivity of 25.4-mm diameter cylindrical cores of sedimentary and igneous rocks was measured at a frequency of 1 kHz under ambient conditions after saturation in tap water and in 0.1 M NaCl solution. Between measurements, each rock was stored in contact with its own separate solution that at the start of the experiment was either tap water or O. 1 M NaCl solution. Eighteen rocks having porosities between 0.07 and 42 percent were investigated; ten were sedimentary, eight were igneous. All solution conductivities were measured employing a dip cell. The time dependence of the conductivity was investigated as well as the range of validity of Archie's law. The formation factor and conductivity of rock specimens and their reacting solutions display time-dependent behavior up to 8,000 hours. The formation factor and electrical conductivity depend on the salinity of the pore fluid, the rock porosity and permeability, and the clay minerals present in the rock.

INTRODUCTION

We are currently investigating rock-solution interaction and its effect on electrical properties of rocks as a function of time, porosity, pore solution concentration, frequency, specimen aspect ratio, and Soxhlet extraction procedures. This work is part of a program to construct a laboratory data-base as an aid in the interpretation of field geoelectrical data. We1 previously observed that the formation factor and the electrical conductivity of the Pictured Cliffs sandstone (permeability range, 7Ã?10â?'4â?'4Ã?10â?'1 md; porosity range, 3.8 to 4.9 percent) display time-dependent behavior when the sandstone is saturated in tap water. Pretreatment of the rock by Soxhlet extraction lowers the formation factor, F, but does not significantly change the time dependence. Also, Duba et al.2 reported on the Ï? of cylindrical cores of Westerly granite; Nugget, St. Peter, and Kayenta sandstones; and Indiana limestone having aspect ratios (length/diameter) from 2.00 to 0.25. Before measurement, the cores were saturated in distilled water, tap water, and in 0.1 M NaCl solution. Aspect ratio affects least the conductivity of rocks saturated in 0.1 M NaCl; for these rocks a linear relationship exists between log Ï? and log Ï?, commonly termed 'Archie's law.' However, no simple correlation was found between log Ï? and log Ï? for rocks saturated in tap or distilled water. This paper is a progress report on the Ï? and F as a function of time up to 104 hours for 18 rocks saturated in tap water or in 0.1 M NaCl solution at 100 kPa pressure.
Condensate Production – The Nigerian Perspective
Authors: Nwabueze Dili O.
Published: December 2007

High Pressure/High Temperature wells are essentially gas-condensate wells and gas injection is a fundamental exploitation strategy for gas-condensate reservoirs.

Concerted effort towards appropriate exploitation of this type of wells will lead to enhanced and rational production of condensate.

There are four basic sources of condensate; (1) oil well gas plants, (2) gas – condensate field plants, (3) gas well field plants and (4) cycling plants.

Regardless of the source, hydrocarbon condensate is of immense value and relevance to global energy demand.

With regard to Nigeria, condensate production will uplift the economy as condensate production is out of OPEC regulation. Also condensate is more profitable than crude oil on equal volume basis as its price is comparable to the price of naphtha.

Normally the greatest harvest of condensate is from gas – condensate reservoirs operated with cycling plants.

This paper highlights the tremendous benefit of rational production of condensate to our economy and strategic energy reserves conservation.
The Applicability of Concrete Polymer Materials for Use in Geothermal Environments
Authors: Kukachka L.E.
Published: December 2007

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

The feasibility of using concrete polymer composites as materials of construction for handling hot brine was demonstrated in 1972. The results from these tests indicated that the composites had long-term stability in seawater at 177 deg. C and in acid solutions. Since then the work has been extended to develop materials for use in geothermal systems. To date, high temperature polymer concrete systems have been formulated, polymer concrete systems have been formulated, and laboratory and field tests performed in brine, flashing brine, and steam at temperatures up to 240 deg. C. Results are available from field exposures of up to 12 months in four geothermal environments. Testing at two other sites is in progress. Good durability is indicated. Based upon progress. Good durability is indicated. Based upon these results, potential applications in geothermal processes have been identified.

Introduction

The availability of durable and economic materials of construction for handling hot brine and steam is a serious problem in the development of geothermal energy. To date, corrosion and scale incrustations have been encountered in all geothermal plants, and to various degrees, adversely affected plant life times and Dower output.

General guides to materials selection for oxygen-free geothermal systems have been published by Shannon. At a temperature of 120 deg. C and pH less than 6, the use of expensive materials such as pH less than 6, the use of expensive materials such as titanium, zirconium, and Hastalloy C is suggested.

Severe corrosion of carbon steel occurs in aerated geothermal fluids at a temperature of 60 deg. C. The corrosion rate in aerated systems is reported to be 100 times greater than in oxygen free geothermal fluids. As a result, all condensate and cooling water piping at The Geysers is constructed of stainless steel or plastic-lined material. It is also necessary to coat plastic-lined material. It is also necessary to coat all concrete surfaces that come in contact with water with coal-tar epoxy compounds or synthetic rubber.

The corrosion rate of carbon steel is highly dependent upon the pH of the brine. At the predicted pH of 4.9 for oxygen-free Salton Sea brines predicted pH of 4.9 for oxygen-free Salton Sea brines and a temperature of 50 deg. C, a service life of less than 15 yr is estimated. At a pH of 4, the estimated service life is 2 yr.

Electrochemical attack due to high sulfate containing soils present in many parts of the western states may restrict the use of carbon steel pipe in the development of medium temperature geothermal reservoirs.
Down-Hole Corrosion in a Salton Sea Geothermal Well
Authors: Treseder Richard S. , Wieland Rita
Published: December 2007

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

Corrosion data were obtained in a well in the Salton Sea Geothermal Field. These data were obtained from inspection of steel tubing removed from the 4200-foot well and from specimens of various alloys exposed at the bottom of the well. Analyses were made of scale on the tubing surface at five locations of varying depth. Corrosion data were obtained also from specimens exposed in surface equipment handling the steam and high salinity brine produced by the well.

Corrosion of the API Grade J-55 tubing was characterized by extensive pitting. The maximum localized corrosion rate varied from 2000 mils/yr at the bottom of the well to about 100 mils/yr at the top. The principal composition difference among the five principal composition difference among the five scale samples was in the silica content, which varied from 3% at the bottom to 27% at the top. Thus, it is possible that silica deposition is a factor in the reduced corrosion observed at the top of the well.

Of the alloys exposed at the bottom of the well, the least corrosion was observed with Type 316L stainless steel and Inconel 600 (2 mils/yr or less). Cracking was observed with stressed specimens of Type 410 stainless steel, Monel 400, Monel K-500, and Inconel X-750, but not with Type 316L stainless steel and Inconel 600.

Introduction

Some years ago Shell Oil Company drilled two wells in the Salton Sea Geothermal Field. This project was subsequently abandoned. As part of the exploratory program, corrosion data were obtained both on program, corrosion data were obtained both on the surface and downhole. In view of the current interest in the possible exploitation of the geothermal energy resources of this field, it was decided to publish the preliminary corrosion test data that were preliminary corrosion test data that were obtained during this early program.

Corrosion data were obtained from stressed and unstressed specimens exposed at the bottom of one well, and from similar tests in surface equipment handling the steam and high salinity brine produced by another well in the same field.
A Parallel Multi-Block Black-Oil Model in Multi-Model Implementation
Authors: Lu Qin , Peszynska Malgorzata , Wheeler Mary F.
Published: December 2007

We discuss the multi-block algorithm for an implicit black-oil model as implemented in a multi-phase simulator framework IPARS. The multi-block algorithm consists of decomposition of the simulation domain into multiple non-overlapping subdomains or blocks according to the geometric, geological and physical/chemical properties, distribution of wells, etc. Each block can have its own grid system, and the grids of the neighboring blocks can be non-matching on the interface, which allows, for example, for local grid refinement, or discrete fault or fracture modeling. Adjacent blocks are coupled across the interface by a set of conditions imposing continuity of the primary variables and component mass fluxes, which is realized with the use of special interface mortar variables. The resulting system is solved by an interface Newton procedure. Regularization techniques and preconditioners are proposed to improve the performance of the solver. The multi-block technique is effective and scalable, as shown by our numerical experiments. In addition, we present how the multi-block black-oil model has been used in the coupling of different physical models.
Modeling Asphaltene Precipitation and Dispersive Mixing in the Vapex Process
Authors: Nghiem Long X. , Sammon Peter H. , Kohse Bruce F.
Published: December 2007

This paper describes the modelling of two important aspects in the simulation of the Vapex process for heavy oil: (1) dispersive mixing and (2) asphaltene precipitation.

The growth of the solvent chamber in the Vapex process is controlled by molecular diffusion and convective dispersion. It is shown that transverse dispersion is the dominant mechanism for fluid mixing at the solvent-oil interface. Simulation results obtained with both longitudinal and transverse dispersion, and with transverse dispersion only are illustrated and discussed.

The asphaltene precipitate is modelled as two solids: solid 1, which is in equilibrium with the asphaltene component in the oil phase, and solid 2, which is formed from solid 1 through a chemical reaction. Solid 2 can be used to represent the association of asphaltene and resins molecules and its precipitation can be made irreversible.
Representation of Crossflow Effects in Advanced Wells in a Multipurpose Reservoir Simulator
Authors: Caillabet Y. , Fabrie P. , Lemonnier P. , Masson R. , Ricois O.
Published: December 2007

Wellbore crossflow can have an important effect on the well production in highly stratified reservoirs. This phenomenon may also appear using EOR techniques or in advanced wells. In those cases, crossflow must be accurately represented and shutting the crossflowing layers may create significant errors on the forecast production and severe numerical problems. This paper describes the method which has been implemented in an all-purpose reservoir simulator. Our method handles both Black Oil and compositional models in a fully implicit scheme. The wells are discretized in different segments where pressure and compositions are determined. These segments generally correspond to the perforated reservoir cells. The wellbore equations are decoupled from the main Newton resolution for CPU time reduction reasons. The characteristic time-scales in the reservoir and the wells are very different, i.e. the well variables vary more rapidly than the reservoir ones. To ensure good simulation times, cheap computations are made on the wells to reach a pseudo steady state prior to the Newton resolution.

The crossflow model is used on both vertical and horizontal wells and also multilateral wells. Well control can be managed using the build-in algorithms that have been extended to crossflowing wells.

Simulation runs showing the accuracy and reliability of the crossflow modelling are presented. The numerical solution is compared with the results from other studies and with a semi analytical method.
The Calculation of Pseudo Functions Using Potential Averaging Methods
Authors: Darman N. H. , Pickup G. E. , Sorbie K. S.
Published: December 2007

A number of methods for calculating dynamic pseudo-functions have been developed over the years although there is still a lack of understanding as to why a certain method will succeed in some cases but fail in others. In this paper, we describe the results of an assessment of several methods, namely the Kyte and Berry (KB) method, the Stone method, the Hewett and Archer (HA) method and the Transmissibility-Weighted (TW) method. We have analyzed the equations for deriving the methods and investigated the results of numerical simulations in a variety of cases to enable us to gain new insights into these, and related, upscaling methods.

We start with immiscible gas/oil displacements in horizontal cross-sectional models with 2D → 1D scale-up. For such cases, the potential drop along the system is equal in both phases, i.e. ΔΦo = ΔΦg. Therefore, any method which maintains this equality will be successful. This is the case for the Stone, the HA and the TW methods, but not for the KB method, which uses relative permeability weighting. Despite the fact that the HA and TW pseudos are calculated differently and the shapes of the relative permeability curves are different, the resulting fractional flow curves are identical and hence identical results are obtained in terms of recovery and breakthrough. When the model is dipping, the pressure drops are different in each phase, and the Stone method (which always assumes that ΔΦo = ΔΦg) fails while the HA and TW methods still succeed.

In more complicated models, with 2D → 2D or 3D → 3D scale-up, the fluid mobilities are more important, because they govern the global pressure field and hence the flow paths of the fluids through the system. We show that the HA and TW methods both produce accurate results, provided directional pseudos are used.
Numerical Simulation of Oil Displacement by Water in a Vuggy Fractured Porous Medium
Authors: Rivas-Gómez S. , González-Guevara J. A. , Cruz-Hernández J. , Galindo-Nava A. P. , Camacho–Velázquez R. , Islas-Juárez R. , Pineda-Muñoz A.
Published: December 2007

This paper presents a numerical simulation study of the flow behavior within a vuggy fractured medium when oil is displaced by water. The experiments were conducted with an acrylic cell, where fractures were represented by channels of 2 mm wide, 1.7 mm depth and 16 cm long, whereas the vugs were represented by cylinders of 1 cm diameter and 1.7 mm depth. The experimental runs were carried out at different water injection rates between 2 and 200 ml/h and variable pressure between 0.006 and 0.910 psi.

The simulation runs, carried out using Eclipse 300 reservoir simulator, required to discretize the domain by using a rectangular grid with 2 mm square cells. Each cell in the vugs was divided into 3, 4 and 5 parts to approximate the vugs shape.

To simulate correctly the phenomena that occur in the experimental cell, it was necessary to try 3 different two-dimensional grids (up to12000 cells were used). It was also necessary to generate relative permeability curves and its corresponding capillary pressure curve.

Furthemore a method to calculate the capillary pressure is presented, both when the wetting or nonwetting relative permeability is available.

A good representation of the lab results was obtained through the simulation. This is relevant as an application of a reservoir simulator to study the dynamical behavior of fluids at this scale.
Environmental Risk Assessment of a Leakage based Injection Water Discharge from Draugen on the Norwegian Continental Shelf
Authors: Vik Eilen Arctander , Oen Amy , Edvardsson Trym , Isaksen Tor Finn , Flatval Kirsti , Ystanes Lars
Published: December 2007

The Draugen platform is operated by A/S Norske Shell and is located at Haltenbanken on the Norwegian Continental Shelf. In 1998 a significant leakage was verified from two mini-flow valves in the injection water system on Draugen. An environmental concern was associated with the chemicals that were periodically discharged to sea via the seawater return flow. In addition to implementing the necessary measures in dialog with the Norwegian environmental authorities, A/S Norske Shell conducted an environmental risk assessment of the discharge.

The risk assessment was conducted using ecotoxicological data and relevant information provided by the chemical supplier, and relevant site specific information from the Draugen field. The assessment was performed utilizing the principles in the CHARM (Chemical Hazard Assessment and Risk Management) model, which is applied in several OSPAR countries.

Three discharge scenarios were addressed. The paper outlines the steps carried out in the environmental risk assessment and describe the potential environmental risk to the marine environment, caused by the discharge. The paper will also address the measures implemented and discharge reductions achieved, resulting in a close to zero discharge of injection chemicals in 1999.
Fracturing Fluid System Concentrate Provides Flexibility and Eliminates Waste
Authors: Terracina John , Parker Mark , Slabaugh Billy
Published: December 2007

A fracturing fluid system concentrate has been developed for hydraulic fracturing operations. The concentrate contains a hydrated polymer, a clay-control additive, a surfactant, and buffers. It can be combined readily with water to provide the proper base gel viscosity for the desired application. The stored mixing water that is added to the concentrate can be fresh water or seawater. Hydration is instant; therefore, no work tanks are required. Cleanup is simplified because all of the additives are in the concentrate, and the mixing water that is added to the concentrate remains unchanged. Therefore, the unused water can be disposed of without environmental concern.

The concentrate reduces the amount of materials required on location and offers greater flexibility in increasing or decreasing the polymer load during a treatment. The concentrate can be prepared in advance and transported to a location to be used for a treatment. This eliminates the need to mix fluids from dry materials on location and the potential waste of those fluids if the treatment is delayed. The concentrate is stable for long periods of time, and it can be returned or used at another location if necessary.

The ability to change the fluid system viscosity and to stop fluid mixing provides new flexibility in designing hydraulic fracturing treatments and eliminating waste on location if extensive delays occur.
New Low Viscosity Ester is Suitable for Drilling Fluids in Deepwater Applications
Authors: Burrows Kim , Evans Joannah , Hall John , Kirsner Jeff
Published: December 2007

High biodegradability and relatively low toxicity have long made esters universally recognized as the best base fluids for synthetic-based muds in regards to environmental performance. A major limiting factor in the use of ester-based fluids, particularly in deep water, is the inherently high kinematic viscosity, a condition that is magnified in the cold temperatures encountered in deepwater risers. These higher viscosities are believed to be especially critical in deepwater wells where lack of overburden causes a severely narrowed window between pore pressures and fracture gradients. Other implications of these higher viscosities include limitations on oil/water ratios, mud weights, and drill solids tolerance.

A new low viscosity (LV) ester has been developed which overcomes these limitations while maintaining the significant environmental advantages of the original esters. The new LV ester has a kinematic viscosity nearly equal to that of currently used internal olefins. It allows formulations of drilling fluids that can be used effectively in virtually all drilling applications in the Gulf of Mexico (GOM), including deep water.

The GOM test protocol was developed to prove the viability of the LV ester as a base fluid. This protocol was designed to consider all conditions drilling fluids are expected to encounter during the course of a well. It evaluates the temperature stability, low temperature rheological properties, and the contamination tolerance of drilling fluids formulated with an LV ester base fluid. Three LV ester fluids were subjected to this protocol: an 11.0 ppg mud; a 14.0 ppg mud; and a 16.0 ppg mud. Results from this extensive laboratory testing indicate new LV ester-based fluids have overcome previous limitations, exhibiting exceptional cold temperature rheological properties, the ability to use a wide range of mud weights and oil/water ratios, and a high tolerance to contamination. In July 2000, an LV ester-based drilling fluid was used to drill a 3651 ft. interval of a GOM well in 3,669 ft. of water. The LV ester fluid performed well in comparison to the same interval drilled on an offset well with an internal olefin fluid. The initial results from that field trial are included in this paper.
Gaia Driving the Greenhouse Effect
Authors: Owen Kevin C. , Blythe Brad J.
Published: December 2007

There is concern that the build-up of greenhouse gasses (GHG) in the atmosphere may have significant environmental impacts. Despite voluntary reductions and various international initiatives, such as the Kyoto Protocol, the worldwide emissions of GHG continue to rise. For example, the 1997 emissions of GHG in the United States were more than 11% greater than the 1990 levels. By 2010, the GHG emissions of the United States may be more than 20% higher.

The authors of this paper suggest there may be forces beyond human control compelling human society to contribute to the greenhouse effect. The authors suggest the release of the GHG, particularly carbon dioxide, to the atmosphere may be caused by the operation of the Gaia hypothesis. The Gaia hypothesis, developed by Lovelock and Margulis in the 1970s, theorized that the Earth functions as a self-regulating system to maintain conditions on the surface of the planet within certain environmental limits.

The Recent atmospheric levels of carbon dioxide are believed to be significantly lower than the levels that existed over geologic time. The carbon dioxide levels predicted by the year 2100 by some modelers will approach the atmospheric concentrations of this gas that have been estimated for the Carboniferous Period. The year 2100 levels would still be between nine and 18 times lower than carbon dioxide concentrations that have been estimated for the Paleozoic Era. Conversely, if the carbon dioxide concentrations were to continue to drop, as has been the trend since the Paleozoic, the levels may be insufficient to support photosynthesis.

Previous researchers have suggested that, operating under the Gaia hypothesis, the biosphere and the terrestrial environment may act to moderate the impacts arising from the greenhouse effect. The authors of this paper suggest that the functioning of the Gaian forces may actually be driving the human species to contribute to the greenhouse effect.

Human activities may be fulfilling a need of the biosphere by releasing buried carbon reserves to the environment. This reclamation of the buried carbon reserves may ensure that biological productivity is maintained, and increased, over time. If so, greenhouse control measures should focus on measures that accelerate the removal of carbon dioxide by the biosphere, sequestering carbon dioxide from the atmosphere.
E&P Waste Management in the Orinoco Delta
Authors: Melchor A. E. , Da Costa A. , Rodriguez C. , Peña J. R.
Published: December 2007

Tropical wetlands and the presence of indigenous people with an ancient culture and strong economic dependence on natural resources, made the Pedernales field an environmental and social sensitive location. The challenge for BPA was to operate in this area without disrupting the lifestyle of the nearby settlements while preserving the environment.

Pedernales field was designed as a zero discharge operation, where the main was streams were to be re-injected. However, due to operational constraints, the initial waste management strategy had to be changed to one that also allowed the disposal of wastes in an environmentally sound way. Waste recycling, bio-treatment and temporary off site treatment and disposal were the key processes of the new waste management strategy.

During 5 years of operations, a total of approximately 2.6 MM bbl of E&P waste were handled and disposed successfully. Poor area drainage, combined with high annual rainfall and low natural soil supporting capacity, required the use of non-conventional tools and equipment; this was more evident for the disposal of drilling cuttings.

Drilling cuttings were handled by turning them into slurry using a specially designed mixer, and then pumping the slurry to a distance of up to 2 Km from the storage barge. Oil degradation from 6%, oil and grease, down to 1% was accomplished in approximately 180 days. This is considered to be a short time taking into account the high level of soil/waste moisture saturation. Continuous monitoring of water and soil with a simple on-site laboratory proved to be adequate and cost effective for process control and prevent environmental pollution.
A Model For Predicting Corrosion Rates In Oil Wells Containing Carbon Dioxide
Authors: Garber J. D. , Farshad F. , Reinhardt J. R.
Published: December 2007

A computer model has been developed which is capable of predicting the physical condition and corrosion rate inside of a vertical oil well at various depths. These wells can be under naturally flowing or gas lifted conditions.

The windows based model contains 4 specific parts, which have been described in detail. The programs which provide the physical descriptions are the temperature program, the phase equilibrium program, and the non-annular flow dynamic program for pressure drop calculation. The model loops until pressure convergence is achieved. At this point various parameters have been selected which predict the uninhibited corrosion rate. An expert system has been developed which adjusts the predicted corrosion rate based on various field parameters.
Multi-Zone Injection by Limited-Entry Through Tubing
Authors: Wegis Anna
Published: December 2007

Multi-zone limited-entry injection through casing can have a serious problem – the inability to achieve efficient recovery due to lack of steam conformance. Poor sweep effiency results in steam migration into unwanted sands, cold temperatures in areas needing a steamchest, and an overall lack of oil recovery.

The failure of limited-entry injection through casing was noticed after a portion of Texaco's Kern River lease failed to achieve steam breakthrough. In July, 1996, this portion of the field had undergone a recompletion, in two distinct sands, utilizing casing limited-entry technology. After several years of injection, one sand had achieved a 0% increased recovery and the other sand had only achieved a 57% sweep efficiency. Because the cost of steam is one of Texaco's main expenses, it is important to use this resource effectively and economically. Limited-entry injection through tubing has proven to be a more efficient method for multi-zone flooding and is widely used throughout Texaco's Kern River operation.

The summer project, as a chemical engineering intern in the productions department, was to prepare and implement programs to reconfigure the field from limited-entry-casing injection to limited-entry-tubing injection in an economical and environmentally safe manner.

Multi-zone limited-entry injection through tubing is the most effective, economical, and environmentally safe answer. During August, 2000, the 20 injector wells in the project area underwent this reconfiguration process, the results of which are being awaited. This paper will document the process utilized to complete the project during the internship and the environmental, health and safety processes that were implemented.
Use of Surfactants to Recover Oils From Groundwater
Authors: Jayanti Shekhar , Pope Gary A. , Weerasooriya Vinitha , Zhong Lirong , Varadarajan Dwarakanath , Taimur Malik
Published: December 2007

Laboratory phase behavior and soil column experiments were conducted using branched alcohol propoxy sulfate surfactants to evaluate their effectiveness in removing gasoline and diesel range hydrocarbons from contaminated groundwater. Very low residual oil saturations were achieved with a much smaller amount of surfactant than typically required in surfactant enhanced aquifer remediation (SEAR). This type of surfactant has been shown to be both robust and efficient even when used at low temperatures and without co-solvent.
An Experimental Study of the Effects of Drilling Solids on Frictional Pressure Losses in Coiled Tubing
Authors: Shah Subhash N. , Zhou Y.
Published: December 2007

The drilling solids content is an important consideration in Coiled Tubing Drilling (CTD) operations. This paper presents an experimental investigation of the effects of drilling solids on frictional pressure losses in Coiled Tubing (CT) using a sophisticated full-scale coiled tubing test facility for an industry – university joint research project. The facility consists of seven reels of coiled tubing with diameters of 1", 1-1/2", and 2-3/8", fluid mixing and pumping equipment, and data acquisition system. Fluids investigated include solid-free polymer solutions at various concentrations, and real drilling fluids currently used in the drilling industry. The rheological properties of test fluids were evaluated using Fann and Bohlin viscometers. Standard industry drilling solids (Rev Dust) were added to the drilling fluids to simulate the effect of drilling solids on frictional pressure losses. Flow tests results indicate that as solids concentration increases, the frictional pressure losses increase significantly. The effect of lubricants on friction reduction in coiled tubing was also investigated. It was observed that the lubricants investigated could effectively reduce the friction pressure loss in coiled tubing. The analysis of experimental data has been focused on the effect of solids concentration, lubricant concentration, coiled tubing geometry as well as drilling fluid rheology.
Zone Selection and Production Prediction Using Advanced Logging Technology
Authors: Grieser Bill , Hill Britt , Brinska John , Stout Rex
Published: December 2007

Completing wells with multiple pay sections can be difficult and costly. With limited capital allocated at completion time, the geologist and the completion engineer are faced with deciding how to spend the available funds to attain the best return on investment (ROI) or net present value (NPV).

A process has been developed for selecting and ranking multiple pay sections and for giving accurate post-stimulation production estimates with advanced logging technology, such as magnetic resonance imaging (MRI), in conjunction with a production reservoir simulator.

This process ranks multiple pay sections by hydrocarbon storage capacity (ϕeff)(h), and producing capacity (kh). Initial productions (IP's), Estimated Ultimate Recoveries (EUR's), or projected cumulative production is then predicted for each section with variable stimulation half-lengths (Xf) or skin values (S). Output can be displayed on the log or in a tabular format.

NPV, ROI, or the internal rate of return (IRR) can be estimated for each stimulation scenario. These estimations can help operators justify stimulation job size and completion cost for each section of pay selected, giving the operator an additional tool for deciding how to best spend completion dollars.

The ranking process can be performed rapidly, and it provides a producing potential before setting pipe. This paper illustrates the process with six field examples from the Granite Wash formation in the Ammunition Field of Washita County, OK. Actual production is compared to predicted production for each well.
A New Approach to the In-Situ Measurement of Rock Properties
Authors: Cole J. H. , Reynolds R. R. , Weinberg D. M.
Published: December 2007

Although amazingly simple in concept, the downhole orbital vibrator is assuming an important and growing role in wellbore applications that include subsurface diagnostic and imaging concepts. The vibrator was first intended as part of a low-frequency shear-wave logging tool. It quickly found a more important application as a dowhole seismic source for crosswell imaging. It is now being investigated as the basis for new logging concepts for the in situ measurement of important rock properties including fractures.
Size of Oil Droplets Under High-Water-Cut Conditions
Authors: van der Zande M. J. , Janssen P. H. , van den Broek W. M. G. T.
Published: December 2007

In this paper the oil droplet size distribution as present during conventional high-water-cut oil production is discussed. The analysis is mainly based on the results of laboratory work on, firstly, core-flow experiments and, secondly, break-up in model chokes. Downhole, the size distribution is governed by the flow of oil and water out of the reservoir sections near the wellbore. It is expected that the smallest oil droplets will be in the 10–15 μm range, while the largest droplets are, presumably, of the order of centimeters. In the tubing, breakup of the largest droplets may occur, so that, eventually, the width of the size distribution will decrease somewhat in the sense that very large droplets will no longer be present. Subsequently, due to more intense break-up phenomena in the choke, the size distribution will shift to smaller droplet sizes. Downstream of the choke, the largest droplets will be in the 100–200 μm range. More information is needed for reliable predictions on the occurrence of very small droplets downstream of the choke. It is expected, however, that many droplets of sizes smaller than 10 μm will be present downstream of the choke.
Neural Network Approach Predicts U.S. Natural Gas Production
Authors: Al-Fattah S. M. , Startzman R. A.
Published: December 2007

The industrial and residential market for natural gas produced in the United States has become increasingly significant. Within the past ten years the wellhead value of produced natural gas has rivaled and sometimes exceeded the value of crude oil. Forecasting natural gas supply is an economically important and challenging endeavor. This paper presents a new approach to predict natural gas production for the United States using an artificial neural network.

We developed a neural network model to forecast U.S. natural gas supply to the Year 2020. Our results indicate that the U.S. will maintain its 1999 production of natural gas to 2001 after which production starts increasing. The network model indicates that natural gas production will increase during the period 2002 to 2012 on average rate of 0.5%/yr. This increase rate will more than double for the period 2013 to 2020.

The neural network was developed with an initial large pool of input parameters. The input pool included exploratory, drilling, production, and econometric data. Preprocessing the input data involved normalization and functional transformation. Dimension reduction techniques and sensitivity analysis of input variables were used to reduce redundant and unimportant input parameters, and to simplify the neural network. The remaining input parameters of the reduced neural network included data of gas exploratory wells, oil/gas exploratory wells, oil exploratory wells, gas depletion rate, proved reserves, gas wellhead prices, and growth rate of gross domestic product. The three-layer neural network was successfully trained with yearly data starting from 1950 to 1989 using the quick-propagation learning algorithm. The target output of the neural network is the production rate of natural gas. The agreement between predicted and actual production rates was excellent. A test set, not used to train the network and containing data from 1990 to 1998, was used to verify and validate the network performance for prediction. Analysis of the test results shows that the neural network approach provides an excellent match of actual gas production data. An econometric approach, called stochastic modeling or time series analysis, was used to develop forecasting models for the neural network input parameters. A comparison of forecasts between this study and other forecast is presented.

The neural network model has use as a short-term as well as a long-term predictive tool of natural gas supply. The model can also be used to examine quantitatively the effects of the various physical and economic factors on future gas production.
Open/Cased Hole Inflatable Whipstock Anchor
Authors: Cundiff David W.
Published: December 2007

The open/cased hole Inflatable Whipstock Anchor, (IWA), was designed to operate in a wide range of casing weights and hole sizes. It was originally conceived for cased hole applications but has proven adaptable to certain open hole applications. The goal was to build a whipstock anchor that would benefit a customer who needs to mill a window in old or damaged casing and reduce response time to the customers request by having a tool available that could be used in various hole sizes.
Experimental Investigation of Xanthan Foam Rheology
Authors: Sani Abu M. , Shah Subhash N. , Baldwin Larry
Published: December 2007

In this work, experimental investigation was carried out on xanthan gel and xanthan foam rheology employing a pipe flow viscometer at 1000 psi. A nominal ½" stainless steel pipe was used as the flow conduit. Xanthan concentrations of 20, 30, and 40 lb/Mgal were used as the gelling agent to prepare xanthan fluids. Surfactant at 0.5% (vol.) was used as the foaming agent. Nitrogen was used as the gas phase. Foams were prepared and tested for qualities ranging from zero to 80% at various shear rates and at temperatures ranging from 75 to 200 °F.

The flow data showed that both xanthan gel and xanthan foam exhibited a behavior analogous to Herschel-Bulkley model fluids. It was found that the foam viscosity increases as the foam quality increases and more viscous liquid phase generated higher foam viscosities. The increase of temperature had an adverse effect on foam viscosity and stability. Viscosity isotherms were generated for the xanthan foam.

New empirical correlations for the xanthan gel and xanthan foam have been developed from the experimental data generated. These correlations are functions of liquid phase properties and foam quality and can be used to predict apparent viscosity of foam fluids for the conditions investigated. The use of these new correlations will provide a better estimation of the xanthan gel and xanthan foam fluid rheological properties.
Total Well Management II
Authors: Podio A. L. , McCoy J. N. , Becker Dieter , Rowlan Lynn , Drake Bill
Published: December 2007

The need of oilfield operators to verify that wells are being produced at their optimum capacity and in a cost effective manner is always present. To reduce operating costs, increase oil production and increase net income requires an integrated analysis of the pumping system including the performance and interaction of all the elements: the prime mover, surface equipment, well bore equipment, down hole pump, down hole gas separator and the reservoir. This analysis is to be made based on data obtained at the surface without entering the well bore and must yield an accurate representation of the conditions that exist on the surface, within the well bore and within the reservoir. Examples of rod pumped wells, ESP pumped wells, PC pumped wells and other well analyses are presented.