bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Team Approach to the Design, Construction, Start Up, and Operation of the World's Most Modern Drilling Rig
Authors: Croucher T. M. 
Published: December 2007

Summary
This paper describes how an integrated team approach was applied to the design, construction, start up, and ultimately the operation of a high technology drilling rig. The rig was built to conform, wherever possible, to the stringent regulations in the Norwegian sector of the North Sea. The paper, which also contains a technical description of the rig itself, also addresses the issue of automation and it's effect on manning of a complex drilling unit and the importance of high quality training of the personnel selected to operate the rig.
In 1994, Phillips Petroleum Company Norway, the operator of the Greater Ekofisk Area fields in the central North Sea, signed a contract for the construction of a state of the art, fit for purpose drilling rig to be located on the new Ekofisk 2/4 X wellhead production platform. The rig was an element of major importance to the Ekofisk II project, the redevelopment of one the largest fields in the North Sea. The start up of drilling on the 2/4 X platform was the first major milestone in the Ekofisk II project and the timely redrilling of the Ekofisk field wells from the new rig was vital to maintain production levels.
On 26th October 1996, exactly on schedule, the first well on the 2/4 X platform was spudded. To date six wells have been drilled by the rig including the fastest well ever drilled in the Ekofisk field. The drilling program is currently on schedule and the rig has operated at an average availability of 98%.
The success of this project can be attributed to a number of factors, however, one element stands clearly as the key success factor—a truly integrated team approach to all phases of the delivery of the rig! From the very beginning, representatives of the real customer of the product, the offshore drilling team, joined the rig supplier's design team to work shoulder to shoulder on the specification and preliminary design of the rig. As the design process moved forward, the customer representation on the team was strengthened. Ultimately, the customer participated in an active manner in all aspects of design, construction, commissioning, and start up of the rig.
This paper will detail both the underlying philosophy and the practical process by which this state of the art rig was successfully built and put to work.
The paper includes a description of the rig itself, a review of how the integrated team approached the various phases of delivery of the rig and an outline of how the project was managed.
The paper then discusses the issue of whether an automated rig can lead to a reduction in manning levels and covers the unique way in which the rig crews rig were trained. Some equipment performance figures are included to demonstrate the successful operational capabilities of the rig, and finally some conclusions are drawn from the lessons that have been learned.
Flow-Pattern Transition and Hydrodynamic Modeling of Churn Flow
Authors: Tengesdal J. Ø. , Kaya A. S. , Sarica Cem 
Published: December 2007

Summary
A thorough review of the existing models for slug-churn transition in vertical and upward inclined two-phase flow is presented. A new transition model based on the drift flux approach and experimental data has been proposed. The new transition model performed the best when it was compared with the existing models and agreed very well with the published experimental data. Two separate hydrodynamic models are presented to predict pressure drop and liquid holdup in churn flow. One is a modified slug model, and the other is a model based on drift flux approach. The performances of the hydrodynamic models are evaluated against a well databank that contains 46 churn flow cases including laboratory and field data.
Pembina Field Polymer Pilot Flood
Authors: Groeneveld H. , George R.A. , Melrose J.C. 
Published: December 2007

Summary
A polymer pilot flood using Pusher 700 as carried out in two adjacentfive-spot patterns in the Pembina field to decrease water channeling in a thickconglomerate zone overlying the sand pay. Although a high viscosity wasachieved in the pilot injection water, only temporary improvements in theproducing- and injection-well behavior were observed.

Introduction
The Pembina field is located in Alberta, Canada, ab out 70 miles southwestof Edmonton (Fig. 1). This large field, which now covers about 500,000 acres, was discovered in 1953 by Mobil Oil Canada, Ltd. The reservoir is astratigraphic trap producing from the Cardium zone at a depth of about 5,000ft. Neither bottom water nor free gas has been found. The field is developed on80- and 160-acre spacing. There are presently about 3,000 active producingwells and 1,400 injection wells. The cumulative production to date is 800million bbl, or about 11 percent of the original oil in place. More than 75percent of the field is under pressure maintenance by waterflooding, miscibleflooding, or gas flooding.
The Cardium zone, which is of Cretaceous age, was deposited under varyingconditions and shows a wide range of rock characteristics. The sand is overlainby a conglomerate section that is extremely erratic in deposition and variablein thickness. Permeabilities in the conglomerate can be very high. Pressuremaintenance performance in the field is severely affected by reservoirstratification in the sand, and particularly by the presence of a welldeveloped conglomerate section. Early breakthroughs and high WOR s are typicalproduction characteristics for wells in areas with thick conglomeratesections.
Considering that the oil in place in the Pembina field is about 7.4 billionbbl and that about 15 percent of the area is overlain by a well developedconglomerate, some improvement of the vertical sweep efficiency throughreducing the adverse effects of the conglomerate could add large reserves tothis field. However, there have been no successful field tests to achieve thisgoal. The purpose of the pilot was to field test the efficiency of Dow ChemicalU.S.A. Pusher 700 in an area of the Pembina field where the stratification hasseverely affected a waterflood.
The viscosity of the Pembina oil is about 1 cp and the flood mobility ratiois less than unity, which is a generally favorable flood situation. Thus, theobjective of the test was not a general performance improvement to correct anadverse mobility-ratio flood, but was to reduce water channeling to bring aboutbetter vertical sweep.
Acid Filtration Under Dynamic Conditions To Evaluate Gelled Acid Efficiency in Acid Fracturing
Authors: Bazin Brigitte , Roque Claude , Chauveteau G. A. , Boutéca M. J. 
Published: December 2007

SummaryDuring the acid-fracturing process, part of the fluid enters the formation, dissolving the rock and creating channels, named wormholes which enhance considerably the volume of fluid leak-off and acid consumption into the formation. To increase the efficiency of the acidizing process, the fluid leakoff must be reduced to improve the fracture acidized length. This paper is a contribution to the study of the phenomenology of the acid fracturing process. An experimental approach, which includes the measurements of wormhole propagation velocities, leakoff volumes, and the observations of the dissolution patterns, has been developed to evaluate acid fluids performance under various representative conditions of acid flow into a fracture.The tests are performed in a tangential cell which allows the solution to circulate in a slot and to penetrate the core at constant pressure drop, thus respecting the geometry encountered in the field process. The experiments herein described have been conducted on limestone cores of different permeabilities. The tests have been performed at room temperature, 50 and 80°C with different overbalance pressures. Fluids are gelled and regular acid.The results are discussed in terms of acid fluid efficiency. The fluid leakoff is evaluated for different initial conditions and linked to the dissolution pattern. The results show that etched patterns suitable for acid fracturing are not developed at the core surface with the gelled acid. However, viscosifying the acid reduces the water filtration by a factor ranging from 3 to 10. Etched patterns are favored by high strength straight acids at low overpressure.
Experimental Three-Phase Flow in Porous Media: Development of Saturated Structures Dominated by Viscous Flow, Gravity, and Capillarity
Authors: Barbu Alexandru , Hicks P. J. , Grader A. S. 
Published: December 2007

Summary
The motivation for this work is the need to understand the formation of oil banks during waterflooding operations as well counter-current gravity driven oil recovery mechanisms. The success of these operations depends on a combination of viscous, gravitational, and capillary forces. This paper focuses on the development of three-phase saturation structures driven by viscous flow, gravity, and capillarity. Three liquids: water, benzyl alcohol, and decane are flowed through glass bead packs. Dynamic water floods of cores saturated with mixtures of benzyl alcohol and decane are described. Saturation distributions in the core are determined using x-ray computer tomography (CT). The injection of water generates a benzyl alcohol bank that displaces most of the decane ahead of it. Benzyl alcohol and decane, driven by gravity, exchange places in the core. This gravity driven counter-current flow is rapid in the presence of low water saturation ahead of the benzyl alcohol bank and within the benzyl alcohol bank. The gravity exchange is slow in the presence of mobile water behind the benzyl alcohol bank. The water saturation structure is stable and is not significantly affected by the counter-current flow of benzyl alcohol and decane. The accumulation of decane at the top of the core triggers a backward migration of a decane tongue. The decane tongue disappears when water injection is resumed and the benzyl alcohol bank re-forms where the decane tongue existed. When mobile decane is not present, significant capillary driven longitudinal fluid transport is observed while the high gradient saturation structure in the transverse direction remains stable. Even high saturation gradients in the longitudinal direction are quite stable. Fluid flow patterns during the shut in periods and displacement mechanisms are proposed.
Gas Migration by Diffusion in Aquifer Storage
Authors: Bagrodia Vijay , Katz Donald L. 
Published: December 2007

Introduction
In aquifer-storage reservoirs, natural gas, primarily methane, displaces water and forms a gas phase in contact with water-saturated porous media. Normally, such waters do not contain dissolved gas initially and the question arises as to how much gas would enter the water phase by diffusion over a period of time. Then, if there is phase by diffusion over a period of time. Then, if there is a hydraulic gradient across the storage field and water moves slowly, how much gas would be carried away from beneath the storage bubble?
Pandey et al. and Chou-Chen provided experimental data on diffusion rates of gases through water-saturated porous media. Their studies give representative values porous media. Their studies give representative values for the diffusion coefficient of methane related to porosity and permeability. Typical aquifer reservoir sands porosity and permeability. Typical aquifer reservoir sands might have 100-md permeability with a lower limit of 1 md and a higher limit of 1,000 md, and with porosities ranging from 12 to 20 percent. Using these reservoir properties, the diffusion coefficients are found from properties, the diffusion coefficients are found from Chou-Chen's correlation of diffusion with permeability.
A typical aquifer-storage reservoir has a gas phase above water-filled porous sand. This sand is assumed to be homogeneous and initially saturated with water that is free of methane. The natural gas is assumed to be pure methane. Formulas were set forth for finding the relative saturation of methane in the water as compared with saturated water at a pressure of 48.3 bar (700 psia) and a temperature of 25 deg. C (77 deg. F).

Diffusion Calculations
By taking a molar balance across an element of water-saturated sand at y ft below the gas-water interface and by applying Fick's law with the effective diffusivity coefficient, one can compute the accumulation of methane in the element with time using Eq. 1.
(1) where
C = concentration of methane in water phase phi = porosity of the sand phi = porosity of the sand De = effective diffusivity coefficient y = depth below the interface, ft t = time, years.
This second-order differential equation can be solved with the help of the initial boundary conditions; that is, initially porous sand is saturated with water, free of methane. At the gas-water interface, water in porous media is saturated with methane. Integration of Eq. 1 gives (2)
where C is the concentration of methane in saturated water at 48.3 bar (700 psia) and 25 deg. C (77 deg. F).
Eq. 2 relates the relative concentration of methane in water to depth below the interface, time, effective diffusivity coefficient, and porosity.
Solutions were made for three cases of 1,100 and 1,000 md. The results of the integration for 100-md sand of 16-percent porosity are shown in Fig. 1.
JPT
P. 121
Stability Analysis of Stratified Oil/Water Flow in Inclined Pipelines
Authors: Fairuzov Yuri V. 
Published: December 2007

Summary
A theoretical study was conducted to investigate flow-pattern transitions in slightly inclined pipelines carrying oil/water mixtures. Two criteria obtained in the linear-stability theory of stratified oil/water flow were used to predict the transition from a stratified-to nonstratified-flow pattern. A comparison of theoretical transition boundaries with published experimental data for horizontal and inclined pipes (±1° and ±5°) was performed. The study revealed that pipe inclination has a significant effect on the stratified-flow region. The results obtained can be useful for the design and operation of crude-oil flowlines and directional wells.
Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well
Authors: Jordan M. M. , Edgerton M. C. , Cole-Hamilton J. , Mackin K. W. 
Published: December 2007

SummaryIn this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well.In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously.This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.
Gel Treatments for Reducing Channeling in Naturally Fractured Reservoirs
Authors: Seright R. S. , Lee R. L. 
Published: December 2007

SummaryThis paper considers some of the reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. We performed extensive tracer and gel placement studies using two different simulators. We show that gel treatments have the greatest potential when the conductivities of fractures that are aligned with direct flow between an injector-producer pair are at least 10 times the conductivity of off-trend fractures. Gel treatments also have their greatest potential in reservoirs with moderate to large fracture spacing. Produced tracer concentrations from interwell tracer studies can help identify reservoirs that are predisposed to successful gel applications. Our simulation studies also show how tracer transit times can be used to estimate the conductivity of the most direct fracture. The effectiveness of gel treatments should be insensitive to fracture spacing for fractures that are aligned with the direct flow direction. The effectiveness of gel treatments increases with increased fracture spacing for fractures that are not aligned with the direct flow direction.
Pumping Wells with Electrical Submergible Pumps
Authors: Parker R.W. 
Published: December 2007

Abstract
This paper reviews the components of electrical submergible pumps with respect to field proven designs which have provided wider application in recent years. Installation procedure is described briefly to point out precautions necessary to obtain long service runs. Performance data for several oil and water supply wells are presented to show what can be expected in the way of operational and maintenance problems and expenses. And finally, the application of electrical submergible pumping is discussed with respect to economics and ultimate recovery.

Introduction
The electrical submergible pump has become a common method of lifting volumes of fluid ranging up to 20,000 B/D. Pump depth may exceed 12,000 ft. Many operators who are not familiar with its varied applications are reluctant to use it because its economic success is not fully understood. The results of several applications economically proven by Marathon Oil Co. in the Big Horn Basin of Wyoming are presented herein to show that the submergible pump has its rightful place in the oil industry.

Description of Equipment
The many sizes and types of submergible pumps are too numerous to mention; but a typical installation designed to lift 4,000 bbl of fluid per day against a total head of 3,000 ft (water) is shown in Fig. 1. Components and costs for this installation are listed in Table 2.
The motor located on the bottom is a 150 hp, 3 phase, 60 cycle, squirrel cage induction type which operates at 3.600 rpm. The protector located above the motor is used to prevent well fluids from entering the motor. Its housing is bolted to both the pump and motor and contains a splined shaft that connects the pump and motor shafts to provide a direct drive.
Petrophysical Analysis of Some Wilcox Wells
Authors: Paine S.M. 
Published: December 2007

Abstract
Relationships are shown between some of the fundamental rock properties of the heterogeneous Eocene Wilcox formation along the central and eastern portion of the Texas Gulf Coast trend. Mention is made that quantitative evaluation, using the electrical logs and established correlations, often are difficult due to:variations in the shale content and cementation of the sand,variations in water salinities,thin bed effects, andinvasion effects.
However, it is pointed out that this does not preclude the use of electrical logs but rather that extra care must be exercised in their interpretation.
Several representative wells along a portion of the trend are reviewed ]to illustrate some of the general characteristics of the formation and the individual utility of some of the logging devices. Particular emphasis is placed on the value of drill cuttings and sidewall cores, as well as capillary pressure data which indicate pore size distribution and which, in turn, are related to porosity, permeability and water saturation. It was concluded that conventional coring usually is not essential for evaluation of exploratory wells along this portion of the Wilcox trend inasmuch as proper logs, in conjunction with cuttings and a few sidewall cores, generally provide adequate data for evaluation.
A recommended evaluation program for down-dip Wilcox exploratory wells penetrating either the upper or both the upper and lower section is presented. It is stressed that the suggested program is necessarily general and therefore flexible and should be considered only as a guidein selecting evaluation procedures.

Introduction
Evaluation of the Eocene Wilcox along the Texas Gulf Coast trend varies from relatively simple cases, as exemplified by a typical well in the upper Wilcox at Mercy, Tex., to the more difficult ones such as found in the lower Wilcox at Sheridan, Tex. In either instance, quantitative evaluation of potential pay sections requires information concerning the porosity, permeability, and formational content (oil, gas or water), or more fundamentally, as Archie has shown, such evaluation should reveal the distribution of each phase (oil, gas or water) within the pores of the rock, The evaluation should not be limited only to permeable rocks containing hydrocarbons, but should include also the impermeable layers as well as the permeable layers containing water.