bluuebunny/crossref_metadata_2025_split huggingface dataset:
Environmental Excellence and Profitability in Asset-based Upstream Organisations
Authors: Parums A. M. 
Published: December 2007

Abstract
The rapid change away from "functional" E&P organisations towards "Asset-based" ones has helped deliver enormous improvements in upstream profitability via de-layering, cost transparency, team integration and alliancing with external providers.
Without these changes the upstream industry would not be facing the future with the self-confidence and growth aspirations which are evident worldwide, both in mature areas such as the North Sea and new regions such as the Caspian.
Prima facie, the decentralising and delayering which are vital to the success of a move to an Asset-based structure carry the risk that a company’s good intentions towards environmental practice will not be delivered in actual operations. However this paper, drawing heavily from BP Exploration’s experience over the past three years, argues that this need not be so. Indeed, provided some key principles are followed, there is real potential for higher environmental performance, largely through liberating the talents and energies of the workforce.
Improved Environmental Compliance And Planning For Oil Field Water Management Using The Latest Information Technology
Authors: Evans R. 
Published: December 2007

Abstract
Oil field water management is increasingly a critical factor with respect to environmental protection and profitability for both new and mature oil field developments. For new oil field developments the integration of water management with oil production planning is vital to avoid environmental damage and bottlenecks to production. For mature oil fields the harmonization of topsides and downhole water control is critical to extending their economic life and continued compliance with environmental regulations, The multidisciplinary and inter-departmental nature of oil field water management, combined with rapidly evolving technology and environmental regulations, makes effective planning and communication vital. An oil field water management system using the latest information technology is described which has the objective to improve design, operation, profitability and environmental compliance. A suite of computer programs, amalgamated by a relational database can be installed on the office network to improve inter-department communication and data accessibility. The software provides expert system step-by-step guidelines for water management through out the oil field life cycle. After existing information on the field is inputted into the database, deficiencies in the data-set are highlighted along with guidance to rectify the shortfalls. Once an adequate data-set is compiled, sub-routines investigate, for example, water compatibilities, reservoir souring, thermal fracturing, water injection and production rates, environmental regulations, water quality requirements, downhole water control and topsides process design. A water handling strategy for the oil field life-cycle is then defined.
Beyond Federal Emission Limits: Steps to Take
Authors: Christy Roger H. 
Published: December 2007

Abstract
The emission control requirements for stationary internal combustion engines in California are being set lower than current federal limits. These limits apply to engines as small as 50 horsepower. Other areas of the country could eventually follow this trend if attainment is not achieved or if air quality standards are tightened. Internal combustion engines can be ripe targets for further controls because of their high aggregate emissions. Problems can occur when the emissions limits are tightened. For instance, when certain districts initially adopted technology-forcing limits, other districts later referred to those levels as available before the technology was even implemented. Occasionally, the limits were so low as to force replacement of many of the engines with electric motors.
Both regulators and industiy must make crucial decisions several years prior to implementing regulations whether they apply to engines or other equipment. These include setting emission limits with only predictions and assumptions on the technology’s reliability and feasibility. Optimistic predictions of control technology performance could lead to significant compliance problems after start-up. On the other hand, ignoring the realities of technological advances could result in setting overly conservative limits. This may lead to the addition of more costly controls on other source types in order to meet total emission reduction goals.
This paper will discuss steps that industry and government should take when developing incrementally more restrictive regulations. These include determining a valid inventoiy of existing engines, predicting future horsepower requirements, determining the amount of power reduction that may occur, analyzing the effects from real-world operating conditions, evaluating both unsubstantiated claims of performance and denials of progress, determining the difference between currently available technology and an arbitrary limit, calculating a realistic incremental cost effectiveness, and finally developing justifiable compliance alternatives.
A Reservoir-Level Approach to Evaluating Cost-Effectiveness of Environmental Regulations on the Natural Gas Exploration and Production Industry
Authors: Smith G. E. , Godec M. L. 
Published: December 2007

Abstract
Industry sources are pushing regulators to perform better cost- benefit analyses of the requirements they promulgate. While it is important to achieve greater balance between the costs and benefits of potential environmental compliance requirements, transparent, comprehensive analysis and comparison of costs and benefits has traditionally been difficult to implement and credibly defend. One alternative approach sometimes used by regulators is to compare the cost-effectiveness of various alternatives ($ per ton of pollutant removed). These calculations are often performed at a very aggregate level, and fail to take into account the site-specific diversity that characterizes the exploration and production (E&P) industry.
A reservoir-based approach can provide a more effective and accurate means of evaluating cost-effectiveness of alternative regulatory approaches, and ultimately, better cost- benefit analysis. Each reservoir can be uniquely characterized by its site-specific environmental and operating conditions to evaluate the application of a requirement in that location. An Environmental Module (EM) being developed for the U.S. Department of Energy (DOE) takes a first step toward building this reservoir level analytical capability for the impact and cost-effectiveness of environmental regulations on natural gas E&P.
This paper describes a reservoir-level approach to cost- effectiveness and cost-benefit analysis that accounts for the site-specific impacts of explicit control technologies. An example of cost-effectiveness calculations for potential regulatory requirements for control of hazardous air pollutants from E&P is provided. The possible benefits of using this approach are discussed.
A Fully-Implicit Thermal Reservoir Simulator
Authors: Naccache P.F. 
Published: December 2007

Abstract
This paper describes a 3D thermal reservoir simulator that models the injection of steam into heavy oil. The variables are pressure, energy and molar densities, and the equations are volume balance and component and energy conservation. The use of energy and molar densities means that there is no variable-switching, and the formulation combines the advantages of volume balance with a fully-implicit code.
A number of example problems are presented, including a large full-field fine-grid model run on parallel processors.

Introduction
We describe a full-featured thermal simulator that works in a number of coordinate systems: cartesian or radial, rectangular or corner-point geometry, and PEBI grids. It calculates non-neighbor connections, and will solve both single- and dual-porosity models. Local grid refinements can be defined, and these are treated simultaneously and fully coupled in the linear solver. A nine-point method can be used to reduce grid orientation effects. Computer memory requirements are minimized by only storing properties and derivatives for active cells.
The new simulator is based on an existing simulator that runs in either compositional or black oil mode. A choice has been maintained and we can either model dead or live oil. We define live oil as having at least one volatile component and dead oil as having none. This paper will describe the general formulation then give examples for the dead oil case. In practice, the dead oil model can be applied to oils that have a small proportion of volatile components as long as these components do not have a significant effect on the simulation.
To solve the thermal effects in the reservoir we choose energy rather than temperature as our new variable. The main advantage of an energy variable is that we avoid the problems of variable switching. In the dead-oil case, for instance, we can use energy to describe the boiling of water at a constant pressure and temperature. By adding an energy variable and an energy conservation equation to the existing formulation, we can simulate the injection of steam or hot or cold water (or hot or cold gas) into the reservoir. The formulation differs from many others in calculating energy bounds for each state in each grid block. The energy in the grid block then defines its state and a flash is performed within that state. We use a conventional fully-implicit discretization of the flow equations. Once the non-linear equations have been set up, they are iterated using Newton's method. The linear equations are solved using nested factorization. The simulator can be run either in scalar or parallel mode, and results are presented for both cases.
Numerical Solution of the Material Balance Equations of Compartmented Gas Reservoirs
Authors: Hagoort Jacques , Hoogstra Rob 
Published: December 2007

Abstract
This paper presents a robust and rigorous method for the numerical solution of the material balance equations of compartmented gas reservoirs. The method is based on the integral form of the material balance equations and employs an implicit, iterative solution procedure. The proposed method enables extension of traditional p/z analysis of single gas reservoirs to complex, compartmented gas reservoirs.
Example calculations of the depletion of a compartmented reservoir show how the p/z is affected by crossflow, reservoir size and depletion rate. The depletion behavior can be rationalized by the observation that depletion of a compartmented reservoir at a constant rate tends to develop a semi-steady-state. A field example is presented that illustrates the capabilities of the extended material balance for the analysis of the past performance of compartmented reservoirs.
An Efficient PC Based Streamline Simulator for Immiscible and Miscible Displacements
Authors: Peddibhotla Sriram , Spath Jeff , Batycky Rod P. 
Published: December 2007

Abstract
Optimizing immiscible and miscible floods are important applications of reservoir simulation. Other important applications include reservoir characterization, history matching, forecasting for project decision making and assessing uncertainty in all the above. Any simulation approach used for these applications should be accurate, reliable, easy-to-use and efficient. Streamline simulation has emerged as an attractive simulation approach that satisfies all of these requirements. In this paper, we describe a new PC based streamline simulation software (STREAM) which allows engineers to quickly simulate and visualize immiscible displacements (waterflooding) and miscible displacements (CO2 flooding). The streamline model is written in FORTRAN90 and the GUI is written in Visual Basic 4.0. Details of the development and the operation of the software are discussed.
Using STREAM, we present a comparison of results between the streamline and traditional (finite-difference) simulation for a mature, West Texas waterflood. The efficacy of the streamline approach and the capability of the software for waterflood optimization is discussed. Timing comparisons between the two methods are also presented. Finally, the advantages and limitations of the streamline method for both immiscible and miscible applications are discussed.
Assessment of Jet Perforated Rock Damage by Finite Element Method
Authors: Asadi M. , Ghalambor A. , Shirazi M. K. 
Published: December 2007

AbstractFinite element method has been employed to evaluate stress distribution within the sandstone formation as the result of a perforation job. The study is based on the followings: a radial reservoir with a perforated well located at the center of the reservoir, characteristics of both 3.5 and 10.5 gr. RDX charges, and the mechanical and thermal properties of the Berea sandstone. This research was performed in three distinct steps: 1) jet temperature effect, 2) jet pressure effect, and 3) combined jet temperature and pressure effects. The results indicated that a 3,5 RDX charge with 2,500,000 psi initial pressure is capable of disturbing rock formation up to five inches longitudinally and two inches radially. The extent of this damage zone for a 10.5 gr. RDX charge having an initial pressure of 4,000,000 psi is eight inches longitudinally and four inches radially. The linear effect is within the first few inches of the perforation runnel entrance. Within this region, rock grains are under an intensive sudden shock pressure wave of 2 to 4 million psi for fraction of a microsecond As a result, rock physical structure will change to metamorphous with a lower bulk density than that of un-shocked rock, causing a sudden decrease in formation porosity and hence formation permeability. This study however, shows that thermal stresses as the result of jet temperature (1,200°F), is insignificant.
Criteria for Back Production of Drilling Fluids through Sand Control Screens
Authors: Marken Craig , Markestad Per , Rorvik Ola 
Published: December 2007

Abstract
By setting sand control screens for open hole completions in the same fluid that was used for drilling into the reservoir, considerable cost savings can be realized through the elimination of the need for displacing to a specialized completion fluid. The control of the particle composition of fluids is crucial in preventing the plugging of the sand control screens. Conditioning the fluid with fine grade shaker screens for removing the larger fluid particles is sufficient to decrease the amount of screen plugging when back producing the drilling fluid in the annulus between the screen and formation. Fluids with a lower solids loading are also beneficial for reducing screen plugging. Particle size distribution measurements have been found to be insufficient in comparison to direct laboratory evaluation the screens at predicting sand screen plugging.

Introduction
Large cost savings are possible if long, horizontal wells can be completed with a sand screen in an open hole instead of gravel packing. The completion costs can be reduced even further if the well can be drilled and completed in the same mud, without using any clean-up fluids or dissolvers. Also, the use of clean-up fluids to remove the drilling mud and filter cake has been shown to increase formation damage in many cases.
Drilling fluids are designed to plug the pores in the reservoir rock and form a thin, impermeable filter cake. It is reasonable to assume that in a sandstone the largest pores will have approximately the same size as the smallest sand grains. Because sand control screens are design to retain the formation sand, they have slots that are narrower than the largest sand grains. Thus, the slots of the sand control screens are not much larger than the largest pores in the reservoir rock.
This means that an operation where the drilling mud must be able to plug the largest pores in the formation sand without plugging slots of the sand control screens, requires very careful planning and control, both of the drilling mud, and of the slot width of the sand control screens. The risk of plugging the sand control screens will be high. For the safe execution of such operations a good understanding of the plugging mechanism is required. One must be able to predict the screen slot width that is required to avoid plugging by a mud with a certain particle concentration and particle size distribution. It would also be useful if one could predict the volume of drilling mud that could pass through a certain screen without plugging it.
When the sand control screen and drilling mud have been chosen, the particle size and concentration of the drill cuttings in the mud must be carefully controlled when drilling through the reservoir. The size of the mud solids can be controlled most easily during drilling by changing the screen in the shale shakers. For this reason it is very important to know what size of openings in the shale shaker screens are required to avoid plugging of a certain sand control screen.
Causes of Sand Control Screen Failures and Their Remedies
Authors: Hamid S. , Ali S. A. 
Published: December 2007

Abstract
A number of completion failures have occurred recently in which screen erosion or plugging has been found to be the primary cause. The screen failures, which occurred during high-rate water packs, have been successfully duplicated in the laboratory through large scale tests. Through these tests and mathematical analyses, the mechanisms involved in the erosive screen failures have been identified. Partial plugging of the screen in the presence of fines leads to high fluid velocities, which cause erosion of the screen by the passage of solid particles through the screen openings. The time required for the erosion to reach critical levels is fairly short i.e. on the order of a few minutes. A number of design and operational guidelines have been suggested to prevent screen failures. A characteristic pressure signature of a screen failure, which can be used for diagnostic purposes, has been identified.
Remote Automatic Control Of Oil Production
Authors: Bayless C.R. , Daughtrey Joe W. 
Published: December 2007

Abstract
The era is approaching when electronic equipment similar to that used by many pipeline companies for the remote control and supervision of pipeline stations may be applied to the production phase of the oil industry. The basic circuits are now being field tested by the Gulf Refining Co. in Timbalier Bay, La.

Introduction
In 1947, the Gulf Oil Corp., as other major oil companies, began developing various systems of automatic lease producing equipment. The early installations were made in the East Texas field and usually consisted of a tank switcher with time-clocked, electric valves for well control. While performing all the operational duties connected with delivery and routing of production from the well to the proper tank, these control systems have safety devices installed on separators, heater-treaters and stock tanks which, upon malfunction of any part of the operation, result in the closing-in of all related wells until conditions have been restored to normal. Such installations have reduced the labor involved in the routine production of oil remarkably. Payouts often are six or eight months. Usually only a few minutes a day supervision are required for the daily tank gauge and routine checks.
The adaptation of this or similar automatic production equipment to other than the East Texas field has been rather slow; however, the increasing development of production in the bay areas and offshore in Texas and Louisiana has given rise to many problems, of which some will undoubtedly best be solved by the application of automatic equipment. To evaluate the feasibility of such a venture, the Gulf Refining Co., in 1952, installed an automatic control system in its Weeks Island field, Iberia Parish, La.
Unlike East Texas, these wells have much higher flowing pressures and operate 24 hours per day; therefore, no timing device for proration of the well is needed at the well head and the well is subject to closure by the control system only when there is a failure of the associated receiving equipment or when the stock tanks are full.
To eliminate the necessity of building a distribution system or laying electric cable to the well for control purposes, a pneumatic system was tried with the flow line acting as the controlling medium. The valve on the well is a pressure operated diaphragm type and is controlled by a bourdon tube type pilot with a high-low shut off. Operating gas for the pilot is obtained from a fabricated drip or scrubber located down stream from the valve. By electrically opening or closing a valve on the battery manifold, the flow line pressure is released or the line is "pressured-up" and, in turn, operates the diaphragm type valve at the well head and effects an opening or closure of the well corresponding to the electric valve on the manifold. A very similar electrically operated valve is also located on all tank filling lines. Working in conjunction with a float switch, this valve provides for a method of electrically directing the oil produced into a tank and a means for determining when each tank is full.
Gathering Gas from Annular Space in Wells in El Tordillo Field
Authors: Buchanan Alejandro , Berra Ricardo , Alvarez Luis , Diaz Alberto 
Published: December 2007

Abstract
El Tordillo oil & gas field is located in the Gulf of Saint George basin, 40 km from the city of Comodoro Rivadavia, Chubut, Argentina. It currently has 380 active wells, using mechanical pumping, distributed over 11,500 hectares.
The produced fluids are collected in 20 batteries. The gas is distributed through a network of gas pipelines with working pressures between 4 kg/cm2 and 7 kg/cm2, depending on geographical location.
Temperatures in the winter can reach as low as −15 C.
The location of field in Argentina is shown in Figure 1.
The produced gas is processed for local sales, in addition to its use in heating and treating oil, and the generation of electrical energy.
This paper describes the studies and tasks performed in order to the capture gas from the casing-tubing annulus, the results obtained in the first stage of the project and the prospects for a wider-scale implementation.

Introduction
The wells in El Tordillo field which work with mechanical pumping produce a GOR on the order of 80–100 m3/m3 with average of water cut of 78%, with gas production totaling 300,000 m3/day. Chromatographic analysis of the captured gas reveals the following molar composition: N2:1.8%; CO2:0.9%; CH4:89.9%; C2H6:3.2%; C3H8:1.5%; iC4H10:0.3%; nC4H10:0.7%; iC5H12:0.3%; nC5H12:0.5%; others:0.9%.
The productive formations are El Trebol (1,400 mts.), Comodoro Rivadavia (1,700 mts.), and Mina El Carme (2,400 mts average depth). The production of hidrocarbons via mechanical pumping methods is complicated by the gas associated with the high liquid flow rates coming from more than 70 productive sands over a large vertical section.
The presence of liberated gas in the liquid stream extracted by the pump not only decreases the volumetric pump efficiency, but also generates stress conditions which shorten the life of the pump and the other materials and equipment in the system.
The alternatives to separate gathering & processing of the production gas are:Venting the gas to the atmosphere through the annular space, thereby producing contamination of the environment and loss of the gas, an option of limited viability owing to the new venting limits being established in the current legislation in Argentina (S.E. 236/93).Pumping the gas with the oil and water up through the tubing, with the already mentioned loss of efficiency and increase in costs.
Because of the undesireability of the alternatives and with an increased gas demand for oil treatment and generation of electrical energy, it was decided to analyze the possibility of capturing the gas independently from the annular space in the producing wells.

Well Testing
An intense well testing campaign was performed to measure and test gas flow rates, using an orifice meter in order to determine the availability of gas.