bluuebunny/crossref_metadata_2025_split huggingface dataset:
Propagation of Chromium(III) Acetate Solutions Through Dolomite Rock
Authors: Jin H. , McCool C. S. , Willhite G. P. , Green D. W. , Michnick M. J. 
Published: December 2007

SummaryChromium(III)-polymer gel systems are often used in permeability modification treatments for flow control. In-depth treatment of the carbonate rock matrix by these systems is of concern because rock-fluid interactions can lead to loss of chromium and may limit the penetration of a gel treatment. This paper describes a study of chromium retention in dolomite cores in the absence of polymer and demonstrates that precipitation of chromium is the principal retention mechanism. Displacement experiments were conducted in which chromium(III) acetate solutions were continuously displaced at different flow rates through Baker dolomite cores with permeabilities from 19 to 25 md. In some experiments, the cores were shut in and the resident fluid displaced and analyzed to determine chromium retention during the shut-in period.There was significant retention of chromium in the core in both continuous and shut-in experiments. In the continuous displacements, effluent concentration profiles were a function of flow rate, indicating that the retention was a rate-dependent process. In the range of concentrations studied, 0 to 1% by weight, the presence of KCl increased the retention rate. At the lowest flow rate used, effluent chromium concentration approached a steady-state value that was much smaller than the injected concentration. The retention capacity of the rock appeared to be infinite.Chromium concentrations at various residence times were compared to values predicted from a kinetic model developed for precipitation from bulk solutions. The kinetic model fit the precipitation rate data well and is consistent with the conclusion that precipitation is the principal retention mechanism. However, the induction period observed in bulk solutions was not present in the data taken in the cores. Precipitation occurred faster in the cores than in the batch experiments. The experimental results indicate that chromium is precipitated at a relatively high rate when chromium acetate solution is in contact with dolomite core material. This loss of chromium may inhibit gelation and limit the depth of penetration of a gel system in dolomite matrix rock.
Interpretation of the Unusual Fluid Distribution in the Yufutsu Gas-Condensate Field
Authors: Ghorayeb Kassem , Firoozabadi Abbas , Anraku Toshiyuki 
Published: December 2007

Summary
It is generally believed that at steady state, a heavy fluid mixture cannot float, without motion, at the top of a light fluid mixture in a cavity. The expectation is that because of pressure diffusion, segregation occurs with the light fluid at the top and the heavy fluid at the bottom. We present, for the first time, an extensive set of measurements in 5-km vertical wells in a large hydrocarbon formation of 1-km thickness with horizontal dimensions on the order of several kilometers that show a high-density fluid mixture at the top of a light-density fluid mixture at steady state. The data in the 5-km wells show liquid in the middle, and vapor at the top and bottom. In the hydrocarbon formation, there is a gradual decrease of density with depth.
A theoretical model based on the thermodynamics of irreversible processes is used to provide an interpretation of the unusual density variation vs. depth both in the hydrocarbon formation and in the long wells, as well as the unusual species distribution in the hydrocarbon formation. The results reveal that thermal diffusion (caused by geothermal temperature gradient) causes the segregation of heavy components in the subsurface fluid mixture to the cold side in the Earth (that is, the top), overriding pressure and molecular diffusion (Fickian diffusion). As a consequence of the competition of these three diffusion effects, a heavy fluid mixture can float at the top with a light fluid mixture underneath. In the past, thermal diffusion has been thought of as a second-order effect. For the fluid mixture in our work, thermal diffusion is the main phenomenon affecting the spatial density and species distribution.
The Effect of Completion Methodologies on Production in the Jonah Field
Authors: Eberhard Mike , Mullen Mike 
Published: December 2007

SummaryImprovements in completion technology have continued to increase the industry's ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field in southwest Wyoming is a classic example of a reservoir commercialized with newer completion technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with a reservoir permeability to gas of less than 10 μdarcy, requiring hydraulic fracturing to be economic. Completion techniques have evolved over the years. In the past 4 years, two techniques have emerged as the predominant completion methods—induced stress diversion and flow-through composite fracture plugs. This study evaluates these different techniques with spatial sampling to compare each well to its offset wells and to identify the completion scheme that yields the best results on cumulative production. From this study, a clear best practice for completing wells in the Jonah field to maximize production was determined.
Field Validation of Transient Swab-Surge Response With Real-Time Downhole Pressure Data
Authors: Samuel G. Robello , Sunthankar Ashwin , McColpin Glen , Bern Peter , Flynn Tim 
Published: December 2007

Summary
This paper describes the field validation results of the transient swab-surge model with real-time downhole annular pressure data. The maximum pressures encountered during tripping or reciprocation are indispensible for making appropriate well-completion decisions. The prediction of swab and surge pressures is of critical importance in wells in which the pressure must be maintained within narrow limits of the pore and fracture pressures. It also plays a major role in running casing, particularly with narrow annular clearances. For these critical cases, a fully dynamic model is required to better estimate the maximum pressures encountered.
This paper presents actual surge-and-swab field data collected with downhole-drilling-data measuring tools during tripping and circulating operations. These data were obtained from Alaska and North Sea wells with a range of hole diameters and different base-fluid muds. The data were compared and interpreted with steady-state calculations as well as a dynamic surge model, which includes the effects of fluid inertia and compressibility, wellbore elasticity, pipe axial elasticity, and temperature-dependent fluid properties.
The sampling rate was specifically increased to 2 seconds and, in some cases, 1 second. This prevents downhole data attenuations and captures the full waveforms more accurately. Different operations were included in the downhole-drilling-data measuring tool runs to cover swabbing, surging, reciprocation, and simultaneous pumping operations during tripping. Model predictions for downhole pressure behavior were in excellent agreement with the measured real-time downhole pressure data.
A New Wellbore Position Calculation Method
Authors: Chia C. R. , Phillips W. J. , Aklestad D. L. 
Published: December 2007

SummaryA method for combining multiple wellbore surveys to obtain a single, composite, more accurate well position is described. Established methods for defining the wellbore position and its associated uncertainty rely on accepting the position obtained from the most accurate survey instrument used in each section of the wellbore. This position is then assigned an uncertainty based on the information from this single survey-instrument run. When a modern wellbore is constructed today, each section may be surveyed for position many times with one or more magnetic, gyroscopic, or inertial survey instruments. By statistically combining the wellbore positions obtained from all the survey instruments run in a given section of the wellbore, a new position, designated the "most accurate position" (MAP), is calculated. The main advantage of the MAP is that its uncertainty is smaller than that of any of the constituent surveys. The major benefits of this technique is facilitating drilling smaller targets at greater distances, allowing new wellbores to be drilled in closer proximity to existing wellbores while maintaining accepted safety clearance rules, and improving reservoir delineation.
Practical and Successful Prevention of Annular Pressure Buildup on the Marlin Project
Authors: Vargo Richard F. , Payne Mike , Faul Ronnie , LeBlanc John , Griffith James E. 
Published: December 2007

SummaryIn late 1999, BP plc experienced a well failure in the Marlin development in deepwater Gulf of Mexico. Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli because of production thermal effects was identified as the most likely cause of the failure.
Performance of the Sussex Area Tensleep Reservoirs
Authors: Blevins T.R. 
Published: December 2007

Introduction
This is a report on the performance of three Tensleep sandstone reservoirs located within an area of 6 sq miles in Meadow Creek and Sussex fields, Johnson County, Wyo. The fields are in the Powder River Basin near Linch, Wyo., which is 8 miles northeast of the Salt Creek field. The surface location of these reservoirs is shown in Fig. 1.
The Sussex field was discovered in July, 1948. There are three separate producing areas including the West Sussex, Sussex, and Meadow Creek fields in the general Sussex area. At the present time there are over 350 producing wells completed in seven producing horizons varying in depth from 3,000 to 9,200 ft.
The initial Tensleep discovery was in June, 1951 in the Sussex Unit A area. The initial Tensleep discoveries in the Meadow Creek Unit and in the Sussex Unit B areas were in March and June, 1952, respectively. Due to market allowables, development of these reservoirs was somewhat restricted until the latter part of 1953. Development since that time has continued on 40-acre spacing in each reservoir.
The Sussex Unit Tensleep A reservoir is approximately 1 ¼-miles long and ½-mile wide. The Sussex Unit Tensleep-Amsden B reservoir is approximately 2 ½-miles long and 1 ½-miles wide. The Meadow Creek Unit Tensleep reservoir is approximately 2-miles long and 2-miles wide.
It will be the purpose of this paper to discuss basic reservoir and geological characteristics, past performance and producing problems of these Tensleep reservoirs. The three reservoirs will be discussed separately in each section in order to bring out similar basic characteristics, as well as to show the contrast in individual reservoir performance. Future performance predictions have been made, but because of the relatively short producing history, they will be discussed only from an academic viewpoint.

Development

Sussex Unit Tensleep A
The Tensleep A discovery well was completed in June, 1951, for a natural flowing potential of 585 BOPD. Development continued on 40-acre spacing, and seven wells have been completed in the reservoir. All wells are open-hole completions and the reservoir is fully developed. The original water-oil contact was at an elevation of –4,330 ft mean sea level as determined lay drill-stem tests and production data.
A Comparison of Various Numerical Wave Prediction Techniques
Authors: Resio D. T. , Vincent C. L. 
Published: December 2007

Abstract
In recent years, the number of wave prediction models has increased greatly. These models range from relatively simple parameterizations of significant wave height as a function of wind, duration, and fetch to rather sophisticated solutions for the generation, propagation, and dissipation of two-dimensional (2D) wave spectra. It sometimes is suggested that any wave model will provide reasonable answers when properly applied, and that most of the deviations between measured waves and predicted waves can be explained by discrepancies between actual and estimated wind fields. Although much of the error in wave prediction almost certainly is related to problems in determining a wind field, this paper examines the specific question of whether there are differences among these models such that even if the wind field were specified perfectly, there would remain significant deviations among predicted waves. First, wave generation under uniform wind fields is compared by use of nondimensional parameters. Then the models are compared again under conditions of time-varying, space-varying wind fields and with irregular fetch boundaries.
We concluded that, in the open ocean with a long-duration, slowly varying weather system, most models produce similar results; however, near a coast or in regions with rapidly varying weather systems, marked differences can be expected from the use of different models.
Performance of the Leduc D-3 Reservoir
Authors: Horsfield R. 
Published: December 2007

Abstract
The Leduc D–3 pool was discovered in 1947 at a depth of 5,300 ft and is one of Canada's major oil fields. The relatively thin oil zone covers an area of 21,640 acres and originally contained more than 400 million bbl of oil in place. It is overlain by a large gas cap and underlain by more than 900 ft of water-bearing reef.
The history of this pool has been outstanding in many ways. The early behavior of the reservoir was dominated by the effects of a wild well which blew oil and gas for six months. Subsequent history indicated that the recovery mechanism consisted almost entirely of gas cap and water drives; however, during 1953, an increase in the rate of pressure decline indicated interference by neighboring pools through a common aquifer. A cooperative committee including almost all Leduc D–3 operators was formed and water injection was instituted in Sept., 1955, to maintain the reservoir pressure and eliminate further shrinkage losses. This project is unique in that pressure is being maintained uniformly throughout the pool with the use of only one injection well which is capable of taking more than 65,000 B/D on vacuum. After one-quarter of the oil in place had been produced, the increase in gas-oil ratio was slight and only one of 535 wells had been abandoned. This pool saw the first application of tubing-submergence completions in Canada and these wells, like most of those completed in a more conventional manner, are still capable of flowing production at rates in excess of 100 B/D without harmful effects.

Introduction
Discovery of the Leduc field in 1947 made oil history in Canada. After more than a decade of fruitless wildcatting in Southern Alberta and Saskatchewan, exploration activity moved northward and Imperial Leduc 1 was spudded 12 miles southwest of the City of Edmonton in Central Alberta.
Using Well Windows in Full-Field Reservoir Simulation
Authors: Mlacnik M. J. , Heinemann Z. E. 
Published: December 2007

SummaryThis paper presents the general and practical applicability of the "windowing technique"1 to model wells in full-field reservoir simulation. Windows modeling the near-wellbore area and the wellblock itself, constructed by the Perpendicular-Bisectional (PEBI) or k-orthogonal PEBI (k-PEBI) method, will be introduced for all wells of a reservoir or for selected "problem wells."The windowing technique, introduced by Deimbacher and Heinemann,1 allows a time-dependent replacement of grids for a defined area during a simulation run. A window can represent any kind of well with a gridded wellbore and an appropriate grid pattern around the well. Such an approach makes the generally used Peaceman well model superfluous. Because the gridded wellbore and the gridblocks around it are small (some cubic feet), the computational stability requires small timesteps and a greater number of Newton-Raphson iterations. It is obvious that this is not feasible if the solution for the full-scale model and the well windows must be performed simultaneously. Therefore, in a first step, the fully implicit solution for the full-scale model will be calculated, but the inner blocks of the windows are solved for the pressure only, without updating the saturations and mole fractions. This solution provides the boundary influx for the windows. In a second step, the windows are calculated for the same overall timestep with up to 1,000 small local steps.This paper presents the general and practical applicability of this method. Windows, constructed by the PEBI (k-PEBI) method, can be introduced automatically for all the wells (vertical, horizontal, and slanted) or for certain "problem wells."For testing purposes, real case field models were used. It will be shown that the quality of the results obtained for the model calculated with integrated radial grids around the wells and small overall timesteps are equal to those obtained for the same model using the windowing and local timestepping techniques. Further, it will be shown that solving the window model with large timestep lengths for the first solution step and small lengths for the second solution step results in equal or smaller CPU times in comparison to the conventional model.
Gas Well Automation
Authors: Fitzgibbon H.J. 
Published: December 2007

Abstract
The design and operation of an automated gas flow and well control system is discussed. The system, designed to reduce operating costs and improve operating efficiency, presently controls 44 gas completions in the Bastion Bay field, Plaquemines Parish, in the marshes of South Louisiana. All wells are controlled from and connected with a central control station via buried multiconductor cable. The reasons remote control is desirable in this field are discussed, the design requirements are listed, the operation of the system is described and the advantages and disadvantages of the system selected are cited.
Introduction
There has been a recent growing tendency for oil companies to reduce or eliminate routine manual labor through the use of equipment designed to operate remotely, unattended and automatically. Systems are presently available for oil field use that can accomplish almost any desired function, limited only by the imagination of the engineer and the amount of investment a company wishes to make. It is the job of the engineer to selectively utilize systems that are practical in application and yet reasonable in cost. The primary function of any automation system is to increase operating efficiency and reduce operating costs. The object of this paper is to review the process by which automation equipment was selected for a large South Louisiana gas field, to describe the automation system selected and to outline its advantages and disadvantages.
Description of Field
Fig. 1 shows the geographical location of the Bastion Bay field, Plaquemines Parish, La. It is located in the Mississippi River delta area, approximately 70 miles southeast of New Orleans. Tenneco Oil Co., acting as operator for Tennessee Gas Transmission Co., operates 44 gas wells located within an area of approximately 8 sq miles. The field is located in a salt marsh adjacent to the Gulf of Mexico and is accessible only by boat. It is also approximately 12 miles from the nearest boat landing or supply point. All wells in the field were drilled from shallow-water, barge-mounted drilling rigs, and all wells are connected through a series of dredged access canals. Fig. 2 shows the field layout and location of the wells and canals. The water depth throughout the field is primarily dependent upon the tide, but ranges from 4 to 8 ft. In this field conservation units are formed about most of the wells, which result in varying working and royalty interests for each completion. Therefore, each gas completion produces through an individual heater and low temperature separation unit, and its production is separately metered. The condensate passes through individual positive volume meters and is then commingled into a condensate pipeline gathering system.
JPT
P. 873ˆ
IMPES Stability: The CFL Limit
Authors: Coats K. H. 
Published: December 2007

SummaryThis work considers cocurrent, 3D, single-phase miscible and two-phase immiscible, hyperbolic flow in a general grid, structured or unstructured. A given gridblock or control volume may have any number of neighbors. Heterogeneity, anisotropy, and viscous and gravity forces are included, while tensor considerations are neglected. The flow equations are discretized in space and time, with explicit composition and mobility used in the interblock flow terms [the IMPES (implicit pressure, explicit saturation/concentration) case].Published stability analyses for this flow in a less general framework indicate that the CFL number must be &lt; 1 or &lt; 2 for stability. A recent paper reported stable 1- and 2D Buckley-Leverett two-phase simulations for CFL limits up to 2. A subsequent paper presented a stability analysis predicting a CFL limit of 2 for one of those simulations. This work gives a different reason for that stability up to a CFL limit of 2.This work shows that the eigenvalues of the stability matrix are equal to its diagonal entries which, for any ordering scheme, are in turn equal to 1-CFLi.This leads to a conclusion of an early paper that CFL &lt; 1is required for nonoscillatory stability. This paper discusses cases in which larger CFL limits between 1 and 2 exhibit stability, the existence or absence of applicable theory in such cases, and the practical contribution of such larger CFL limits to increased model efficiency.
Numerical Simulation of CO2 Leakage From a Geologic Disposal Reservoir, Including Transitions From Super- to Subcritical Conditions, and Boiling of Liquid CO2
Authors: Pruess Karsten 
Published: December 2007

Summary
The critical point of CO2 is at temperature and pressure conditions of Tcrit = 31.04°C, Pcrit = 73.82 bar. At lower (subcritical) temperatures and/or pressures, CO2 can exist in two different phase states, a liquid and a gaseous state, as well as in two-phase mixtures of these states. Disposal of CO2 into brine formations would be made at supercritical pressures. However, CO2 escaping from the storage reservoir may migrate upward toward regions with lower temperatures and pressures, where CO2 would be in subcritical conditions. An assessment of the fate of leaking CO2 requires a capability to model not only supercritical but also subcritical CO2, as well as phase changes between liquid and gaseous CO2 in subcritical conditions. We have developed a methodology for numerically simulating the behavior of water/CO2 mixtures in permeable media under conditions that may include liquid, gaseous, and supercritical CO2. This has been applied to simulations of leakage from a deep storage reservoir in which a rising CO2 plume undergoes transitions from supercritical to subcritical conditions. We find strong cooling effects when liquid CO2 rises to elevations where it begins to boil and evolve a gaseous CO2 phase. A three-phase zone forms (aqueous/liquid/gas), which over time becomes several hundred meters thick as decreasing temperatures permit liquid CO2 to advance to shallower elevations. Fluid mobilities are reduced in the three-phase region from phase interference effects. This impedes CO2 upflow, causes the plume to spread out laterally, and gives rise to dispersed CO2 discharge at the land surface. Our simulation suggests that temperatures along a CO2 leakage path may decline to levels low enough that solid water ice and CO2 hydrate phases may be formed.