bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Water Coning on the Performance of Vertical and Horizontal Wells-A Reservoir Simulation Study of Hassi R'mel Field, Algeria
Authors: Recham R. , Osisanya S. O. , Touami M. 
Published: December 2007

Abstract
Generalized empirical correlations have been developed to predict, (1) critical oil rate, and (2) water breakthrough time in vertical and horizontal wells. Water coning is a serious problem in many producer wells, which increases the cost of producing operations, and reduces the efficiency of the depletion mechanism and the overall recovery.
A numerical simulation was used to analyze the most relevant fluid and reservoir parameters that affect water coning using a 3-D radial vertical well model and a 3-D Cartesian horizontal well model. The method of determining the average oil column height below perforations at breakthrough (hwb), was developed from a stepwise procedure. First, a number of simulation runs was made to investigate the coning performance at different reservoir and fluid properties for both vertical and horizontal wells. Then, for each simulation run, water oil ratio (WOR) was plotted against of average oil column height below perforations (hbp), on a semi-log scale, from which (hwb) was determined. Once the (hwb) data was obtained for all the simulation runs, regression analysis was then used to define the relationship between (hwb) and various reservoir and fluid properties.
An extensive parametric sensitivity analysis of water coning was made to provide data for developing a predictive correlation of calculating breakthrough time and breakthrough height as a function of various reservoir and fluid properties. The simulation outputs are used to develop empirical water coning correlations to predict critical oil rate, and water breakthrough time for vertical and horizontal wells. The parameters were grouped together based on the basic flow equations and the grouping was confirmed by regression analysis. Several field examples from CTH1 area of Hassi R’mel field in Algeria will be discussed.
Impact of Skin Damage on Horizontal Well Flow Distribution
Authors: McMullan John H. , Larson Todd A. 
Published: December 2007

Abstract
One of the common applications of horizontal wells is the development of thin oil columns underlain by bottom water and/or overlain by a gas cap. Vertical wells are not suited in this situation due to the rapid coning of water or gas at reasonable production rates. Horizontal wells correctly positioned in the oil column, however, can produce at high flow rates with very little drawdown. The small drawdown significantly delays the breakthrough of water or gas at flow rates much higher than the flow rates possible from a vertical well.
The flow distribution in a horizontal well designed to develop a thin oil column can be significantly impacted by friction losses in the wellbore. The impact of friction results in a higher drawdown at the heel as compared to the toe of the horizontal well. While this impact is insignificant in lower permeability systems, it can lead to premature water or gas breakthrough at the heel of the well in high permeability systems produced with low reservoir drawdown.
Skin damage is normally undesirable due to its detrimental impact on well productivity. In high permeability systems developed with horizontal wells, however, well productivity is normally not a problem. Skin damage actually diminishes the detrimental impact of friction in horizontal wells by improving the flow distribution. This study investigates the intentional inclusion of mechanical skin damage in a high permeability, North Sea horizontal development. Reservoir simulation was used to justify and design a limited entry completion that was shown to improve flow distribution and oil recovery, at a significantly lower completion cost. The desired uniform flow rate distribution was confirmed by a PLT run in the first well, and through reservoir simulation and history matching.
Performance of Horizontal Wells Completed with Slotted Liners and Perforations
Authors: Tang Yula , Ozkan Erdal , Kelkar Mohan , Sarica Cem , Yildiz Turhan 
Published: December 2007

Abstract
This paper presents a comprehensive study on the productivity and flow efficiency of horizontal wells completed with slotted-liners or perforations. The study is based on a semi-analytical model that couples the flow equations in the reservoir and wellbore. The reservoir model takes into account the 3D convergence of flow around perforations and slots. The wellbore flow model considers the pressure losses inside the horizontal well and the effect of axial influx at the perforations and slots. A new, experimental apparent friction factor correlation is used for horizontal wellbore flow computations with perforations and slots. The model is capable of incorporating the effects of selective completion and non-uniform skin distribution.
The results of this study indicate that software based on detailed semi-analytical models can provide a powerful tool to design, predict, and optimize horizontal well completions. It is also shown that horizontal wells deserve genuine guidelines to optimize their completions. For example, horizontal wells are shown to require significantly lower slot and perforation densities to accomplish optimum PI compare to vertical wells. Similarly, in horizontal wells, the effect of slot or perforation phasing becomes more important as the anisotropy of the formation increases.
Successful Implementation of Shared Learnings and New Technology to Develop a Thin Oil Column With Horizontal Wells in the Mahogany Gas Field, Offshore Trinidad.
Authors: Mackow H. Michael , Ali-Nandalal Jo-Ann , Hassanali Hamid , Staines Michael 
Published: December 2007

Abstract
Horizontal oil well drilling, completion and production techniques have continued to advance through the use of shared learnings and new technology as applied in the most recent BP Amoco field development in Trinidad. The Mahogany field is being developed to supply gas to the Atlantic LNG plant in Trinidad. The 21 Sand reservoir in this field has a 60 foot oil column overlain by a 400 bcf gas cap and underlain by water. As with other fields in Trinidad that have thin oil columns horizontal well technology was selected as the preferred method to develop the Mahogany 21 Sand oil leg. During the front end loading design phase of the Mahogany field development an extensive review of evolving technology and recent world wide experience was undertaken. As well, the front end loading involved a review of the BP Amoco Immortelle (Trinidad) horizontal well program which was in its third phase as the Mahogany front end loading was being completed.
The critical success factors that emerged from the front end loading review were well placement within the oil column, avoid drilling poor quality reservoir, avoid undulating wellbores, the need to understand well performance with very low drawdowns, the need to land the well in the right place and at the right angle. All of these issues were addressed in the Mahogany horizontal well designs and have been successfully implemented.
The front end loading work and continuing optimization of the well designs has resulted in a highly successful 21 sand oil development which is expected to deliver economic results superior to the authorized metrics.
Use of a Chemical Equilibrium Computer Code To Analyze Scale Formation and Corrosion in Geothermal Brines
Authors: Shannon D.W. , Morrey J.R. , Smith R.P. 
Published: December 2007

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

Introduction
The probable size of U.S. geothermal energy reserves indicate we are in the beginning phase of the birth of a new industry. It is easy to visualize 50 to 100 geothermal power plants scattered all over the western United States involving all the electric utilities serving these regions. The development of geothermal energy on such a scale in the next 20 years will require considerable investment. Geothermal power plants will cost $25 to $100 million each. plants will cost $25 to $100 million each. Before such investment in geothermal energy can be justified, a number of questions must be answered including, "Can we assure reliable plant operation over the 20- or 30-year amortization period?" An important part of answering this question hinges on the effects of mineral scaling and corrosion on the performance of geothermal wells and power performance of geothermal wells and power plant components which come into contact with plant components which come into contact with geothermal fluids, and the subsequent plant degradation in electric output and maintenance expense.
Under sponsorship of the Electric Power Research Institute (EPRI), Battelle-Northwest Laboratories (BNW) has undertaken research programs which are aimed at answering some programs which are aimed at answering some of the very complex questions relating to scaling corrosion and power plant performance.
The major part of the material for this paper is drawn from our EPRI work which is paper is drawn from our EPRI work which is about 50% complete. Thus, this paper will concentrate on the problems we see, approaches we are taking to solve them, and some of our initial results.
A prerequisite for the analysis of scaling and corrosion rates in geothermal systems is a comprehensive data base on geothermal brines, and an understanding of which brine components are important. Knowledge of the kinetics of scaling and corrosion processes must be accompanied by an processes must be accompanied by an understanding of the equilibrium conditions of complex, multicomponent brines and associated minerals. Numerous references exist in the geochemical literature for the calculation of equilibrium conditions and the alterations of equilibrium states due to temperature changes. Unfortunately, these studies are inadequate when one considers the extremely rapid changes of state that occur as a geothermal brine passes through a power plant. Supersaturation effects and slow nucleation and growth of crystals an change scaling rates by orders of magnitude during the short residence time of brines in geothermal plant components.
Chemical Movement in Micellar Flooding: Determination of Sulfonates and Polymers by Liquid Chromatography
Authors: Suffridge Fred E. , Taggart Davis L. 
Published: December 2007

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

Abstract
Now liquid chromatographic procedures, column solvent systems and equipment used to determine petroleum and/or synthetic sulfonates and water-soluble polymers in micellar fluids are described. These new procedures are used to determine sulfonate and/or polymer in formulations and in core test effluent polymer in formulations and in core test effluent fluids. Procedures developed have been or will be automated. With automation about two man hours are required to perform 100 sulfonate analyses in a 24-hour period. Analyses have shown that monosulfonated fractions of sulfonates are usually selectively lost (adsorbed) in laboratory core tests.

Introduction
Micellar flooding is one of several improved oil recovery techniques currently being studied by the petroleum industry. By nature it is a complicated multiple fluid bank, chemical process. A typical tertiary micellar flooding process includes injecting a micellar fluid and following it with a mobility-control drive fluid. Most micellar fluids currently used by the industry contain brine, cosurfactants, and petroleum or synthetic sulfonates. Frequently, chemical tracers, water-soluble polymer, and/or solubilized hydrocarbons may also be present. Mobility-control drive fluids typically contain water-soluble polymers (polyacryla-mides or Xanthan gum biopolymers) dissolved in fresh water. Chemical tracers, biocides, and oxygen scavengers may also be present.
As these fluid banks (micellar and mobility control) propagate through cores in lab testing, or through reservoirs in field testing, they are retained and mix with one another and with in-place brine and oil. The propagation and mixing behavior of these fluid banks is studied by collecting samples of injected/produced fluids and analyzing these samples for chemical content. Analyses of produced fluids are compared to injected fluids to study adsorption, interaction, and propagation properties of the chemicals in a propagation properties of the chemicals in a given micellar flooding process.
Chemical costs make up a significant portion of the total cost of a micellar portion of the total cost of a micellar flooding process. Chemicals showing low adsorption in a reservoir environment (actual or simulated) are the most desirable chemicals for micellar flooding. Analyses used to determine the specific components in micellar fluids must be accurate, specific for adsorbed components, and relatively free from interference from other materials present in the samples.
Flow Equation for Foam Flowing Through Porous Media and Its Application as a Secondary Recovery Fluid
Authors: Alizad Tanweer , Okandan Ender 
Published: December 2007

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

Abstract
A theoretical and experimental study of the flow of aqueous foam, of homogeneous and fine bubble size, through unconsolidated porous media is described. An equation was developed to describe the flow of non-Newtonian fluids through porous media and is confirmed experimentally using foam. In the light of the equation, the rheological properties of foam are studied experimentally. Externally generated foam, of known quality, was injected continuously into a porous medium. Both flow rate and pressure drop were measured. Foam is shown to behave as a single-body pseudoplastic fluid in unconsolidated porous media, With the help of experimental data, foam's apparent viscosity was calculated and is found to be increasing with the increase of foam quality.
Experiments also were conducted to displace oil from unconsolidated linear sand packs using foam of different qualities. Foam's ability to displace oil from porous media was observed and was found to be better as compared with water. High-quality foam displaces oil at a relatively lower rate than low-quality foam. Compared with low-quality foam, less high-quality foam is required to displace the same amount of oil.

Introduction
In recent years, the aqueous foams have gained popularity in various petroleum operations because of their specific properties. Apart from enjoying application in oil wells as aerated drilling fluid and in workover and remedial well operations, foams, because of their flow-impeding nature, have potential use as a remedial fluid to combat coning and as corrective fluid to improve sweep of fluid injection processes in heterogeneous reservoirs. They also have been suggested as a way of preventing gas leakage through the cap rock of storage reservoirs. Foams have been used as a means of treating wells to reduce water or gas inflow during oil production. They are being used also as fracturing fluid for the stimulation of oil-bearing formation.
Consideration of factors that operate to limit the recovery of oil by conventional mechanisms led to the development of secondary or tertiary oil recovery methods. The foamdrive method is one of them. Prompted by the known properties of foam, like its high apparent viscosity, attempts have been made in this study and by others to use foam as a secondary recovery fluid.
The Use of High Resolution NMR Spectroscopy for Characterizing Petroleum Sulfonates
Authors: Hsieh W.C. , Shah D.O. 
Published: December 2007

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

Abstract
Natural petroleum sulfonates and synthetic sulfonates were characterized or "finger-printed" using high resolution NMR spectroscopy. Natural petroleum sulfonates are produced by sulfonation of a selected petroleum fraction. Synthetic sulfonates petroleum fraction. Synthetic sulfonates are produced by sulfonation of alkylated benzenes or naphthalenes of the proper equivalent weights. Petroleum sulfonates usually contain unreacted oil, water, and salts in addition to the active petroleum sulfonate. Therefore, the quality and composition of similar petroleum sulfonates may be different if one considers the supply of a petroleum sulfonate at different time intervals petroleum sulfonate at different time intervals or pooling of similar petroleum sulfonates obtained from different suppliers. Characterization of petroleum sulfonates generally includes (1) the average equivalent weight, (2) percentage of unreacted oil, water, and salts, (3) percentage of active sulfonate, (4) pH and solubility of oil or water. A rapid and informative analysis or "fingerprinting" of petroleum sulfonates can be done using high resolution NMR spectroscopy. The relative amount of water, the relative amounts of aromatic and aliphatic protons, the fine structure of the polar group and hydrocarbon chains can be determined by this method. About 20 different types of petroleum sulfonates were analyzed using high resolution NMR spectroscopy.

Introduction
Petroleum sulfonates are widely used as surface active agents in the injection fluid (detergent solution) to lower the interfacial tension between oil and formation water in the tertiary oil recovery process. It was found that a low interfacial tension (LIFT) in the order of 10-2 dynes/cm or less is necessary for the injection fluid to displace the trapped oil after water flooding. Further, it was found that the LIFT can be achieved only if the contacting oil phase is compatible with a given injection fluid. This obviously leads to the suggestion that the molecular structure of petroleum sulfonates is vital to the achievement of LIFT for a given oil.
Natural petroleum sulfonates are generally mixtures of alkyl-aryl sulfonates which also contain unreacted oil, water and electrolytes. It is difficult to identify the individual components in the natural petroleum sulfonates unless each of them is separated. However, a rapid and informative analysis or "finger-printing" of petroleum sulfonates is highly desirable.
Geochemical Equilibrium Codes: A Means of Modelling Precipitation Phenomena in the Salton Sea Geothermal Field
Authors: Miller D.G. , Piwinskii A.J. , Yamauchi R. 
Published: December 2007

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

Abstract
We have used the Helgeson-Herrick geochemical code to predict which minerals will precipitate from Salton Sea Geothermal Field precipitate from Salton Sea Geothermal Field brines. The code's predictions of sulfide-amorphous silica precipitation from the Magmamax No. 1 brine are in good agreement with field tests of scaling, although the observed silicate scale matrix is in amorphous form, rather than the numerous crystalline forms predicted by the code. The code's predictions predicted by the code. The code's predictions of scale precipitation from wells with different brine compositions are also in good agreement with field tests. The code appears to be a useful screening tool, despite reservations about the use of purely thermodynamic predictions in systems with important kinetic predictions in systems with important kinetic constraints.

Introduction
A major goal of the LLL geothermal project is to develop a total flow concept for converting to electric power the thermal energy of high-temperature, high-salinity brines-found in the Salton Sea Geothermal Field (SSGF). LLL's approach to the total flow process calls for passing the entire wellhead product through stationary, specially designed nozzles to form high-velocity jets. These jets then turn an axial-flow impulse turbine that generates electricity. Unfortunately, as the high salinity brines cool and flash (i.e., are made to do work), large quantities of sulfides and silicates precipitate, producing a ubiquitous scale on precipitate, producing a ubiquitous scale on pipes, nozzles, and turbine blades. pipes, nozzles, and turbine blades. The brines are complicated by both the large number of species present and by the complexity of the chemical reactions occurring. Table 1 presents representative analyses of brines from the Sinclair No. 4 and Magmamax No. 1 wells. The brine solutions are very concentrated (4–5 molal, ionic strength 5–6), containing mostly NaCl. There are also significant amounts of Ca+2 and K+, as well as H4,SiO Fe+2, Cu+2, Pb+2, Mn+2, M9712, S-2, CO2, and H2S. Clearly, the precipitation of silica and metal sulfide scale is of special interest because of the scale's harmful effect on plant materials and its unbalancing effect on the turbine.
Precipitation equilibria can be studied by thermodynamic equilibrium calculations (both those done by hand and by computer code) and by experiment.
A Survey of Treatment Methods for Geothermal Fluids
Authors: Phillips Sidney L. , Mathur Ashwani K. , Doebler Raymond E. 
Published: December 2007

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

Abstract
This paper presents a study of methodology used to control geothermal scaling and corrosion. The information used for this study was screened from the geothermal, oil and gas, wastewater disposal, and boiler water treatment industries. This information was evaluated and the current state of knowledge and methodology concerning the treatment of geothermal brines to control scaling and corrosion in geothermal electric power production was assessed. Currently, power production was assessed. Currently, geothermal scale in pipes and wells is removed by physical or chemical methods. There is a growing effort on developing methods to control scale formation for both fresh and spent brines, including pH adjustment and application of an electrical potential for fresh fluids, and coagulation to potential for fresh fluids, and coagulation to treat spent fluids. Current methods of corrosion control center around planned replacement of piping and other plant components, with efforts focused primarily on development of materials with improved corrosion resistance. Recommendations for additional work include the following:chemical and physical characterization of brine and scale compositions;basic data on the mechanism of scale formation and the effects of inhibitors;development of instrumentation to monitor geothermal brine constituents;correlation of laboratory results with field test data, andscreening of currently available commercial inhibitors for application to geothermal brines.

Introduction
Utilization of geothermal energy for power production requires a fluid to extract power production requires a fluid to extract heat from the earth. Major development of geothermal energy in the next 25 years will be in regions where the fluid occurs naturally as hot water and has been in contact with the country rocks for a considerable period of time. The chemical composition of period of time. The chemical composition of the fluids will therefore reflect the composition of the country rock and in general be in chemical equilibrium with it. Because of the wide variety in rock types, the composition of geothermal hot water fluids is expected to vary widely, ranging from several thousand to several hundred thousand ppm dissolved solids combined with dissolved ppm dissolved solids combined with dissolved gases in an aqueous solution.
Considerations for The Effective Regulation of the E&P Sector of the Nigerian Petroleum Industry
Authors: Nwasike Obi Timothy 
Published: December 2007

Abstract
The petroleum industry of Nigeria has a very long history. The management of regulatory matters has not fared so well in the period. A discussion of the issues that could influence good regulatory practices is included in this technical paper. It is concluded that such factors as adequate and regular flow of funds, appropriate skills, information technology and the use of consultants by regulatory agencies are pre-requisites that will ensure an effective regulation of the petroleum sector of the Nigerian economy.