bluuebunny/crossref_metadata_2025_split huggingface dataset:
Theoretical and Experimental Investigation of Water in Oil Transverse Dispersion in Porous Media
Authors: Duan Shengkai , Wojtanowicz Andrew K. 
Published: September 2008

Abstract
Water production is controlled by the size and distribution of water saturation around wells. Reported in this paper is a continuing research into mechanisms causing expansion of the water saturation transition zone (transverse dispersion) in a segregated flow of oil and water approaching a vertical well's completion. The mechanisms – including non-linear (non-Darcy) flow, turbulence, shear rate, flow baffling at grains – all contribute to instability of the oil/water interface resulting in hydrodynamic mixing. Interface instability due to shearing rate has been demonstrated in our recent study on the Hele-Shaw model. In this work, we have evaluated the practical size of the mixing zone around wells, modeled mathematically the effect of flow baffling, and demonstrated transverse dispersion experimentally using a linear physical sand pack.
The maximum size of the mixing zone was evaluated using the turbulence criterion and differential velocity for typical wells' inflow conditions. Critical dimensionless numbers for flow in porous media were used to determine the onset of transverse dispersion. The radial size of mixing zones was then correlated with fluid properties, water cut, and the effective area of well's inflow.
A simple model of "bifurcated flow" was developed to demonstrate the effect of two phase flow baffling in granular porous media. The model shows that the change of flow momentum of the two fluids at collisions with rock grains becomes the major factor causing water dispersion.
A series of segregated (top oil; bottom water) flow runs were carried out using physical model packed with different porous media at a constant pressure drop. The runs were videotaped and analyzed for saturation distribution using a color intensity recognition software. The results clearly demonstrate onset of transverse dispersion of water into the flowing oil. Further dispersion, however, was overshadowed be the dimensional and end-point effects of the model. With a numerical estimation procedure, the initial dispersion rate – computed from the 1-D flow model – is the essential data needed to estimate total dispersion in radial inflow to wells.
Plugging Wells with Hydrated Bentonite, Part 2: Bentonite Bars
Authors: Towler Brian F. , Victorov Herman , Zamfir Gabriel , Ignat Pompiliu 
Published: September 2008

AbstractData for the kinetics of the swelling of bentonite bars are shown and measurements for the friction factor between the hydrated bars and steel and plastic pipe are given. The results are compared with a previously derived equation for pressure containment. These results demonstrate that the bars produce a hydrated bentonite that has similar or better pressure containment than other bentonite solutions. Bentonite has long been used for the plugging of water wells and these bars have been produced for use in the plugging and abandonment of oil and gas wells.
Field Trial of a New Non-Damaging Degradable Fiber-Diverting Agent Achieved Full Zonal Coverage during Acid Fracturing in a Deep Gas Producer in Saudi Arabia
Authors: Solares J. Ricardo , Duenas J. J. , Al-Harbi Moataz , Al-Sagr Abdulaziz , Ramanathan Venkateshwaran , Hellman Ryan 
Published: September 2008

Abstract
Acid fracturing has been an integral part of Aramco's gas development strategy for the vertical wells in the Khuff carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. During acid fracturing, the wormholes created by the reaction, results in excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid, a polymer-based system, are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad.
These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest reservoir quality zones with minimal contribution from the other zones in many cases.
Field trials involving the use of a new degradable fiber technology designed to achieve effective acid diversion during acid fracturing was recently implemented. The trials were conducted in a matrix acid and in an acid fracturing treatments, which were designed and pumped with alternating stages of acid and fiber-laden polymer based pad fluid. The significant viscosity increase achieved in the pad by the addition of fibers and its particulate bridging mechanism would plug off the just stimulated zones effectively, thus diverting the new stage of acid into the non-stimulated porous zones. These fibers degrade and hydrolyze with temperature and time thus leaving the reservoir undamaged.
This paper discusses the planning and design processes leading to the successful implementation of the technology, the experience during the stimulation treatment execution and the excellent post-stimulation results. A production logs was run in the acid fractured well to ascertain the effectiveness of the technology. The results are discussed and compared in the paper with those from offset conventionally acid fractured wells, and the lessons learned throughout the pilot are also shared.
Design of Improved High-Density, Thermally-Stable Drill-In Fluid for HTHP Applications
Authors: Ezell Ryan , Harrison Douglas J. 
Published: September 2008

AbstractAs we approach an age of deeper discovery and petroleum producing wells with hostile environments, the industry need for an elevated-temperature, high-density, low-solids, and non-damaging reservoir drilling fluid or "drill-in fluid" has moved to the forefront of laboratory and applied research. Drill-in fluids are a special class of drilling fluids that prevent formation damage, provide superior hole cleaning, and help minimize wellbore cleanup effort, resulting in increased efficiency from the production reservoir. These fluids address the wide range of difficulties encountered in horizontal drilling, completion, and workover operations.The need for fluids with service temperatures above 300°F has increased beyond the capabilities of traditional biopolymers to create rheologically stable fluids. While some water-based drilling fluids excel at these higher temperatures, their formulations include non-acid soluble solids that are damaging to hydrocarbon-bearing formations and hence undesirable. With higher temperature reservoirs being drilled, there is need for a suitable high-density, high temperature stable drill-in fluid.For the development of the fluid presented in this work, various high density brines were evaluated to achieve fluid weights up to 17.6 ppg (2.1 sg) in order to reduce the amount of weighting agent utilized in the system since these solids can result in high plastic viscosities and create difficulty in the cake removal and clean-up processes. The total amount of CaCO3 bridging material was maintained at a relatively low concentration to produce a thin, acid-soluble filter cake while the bridging particle size was determined by the ideal packing order of the chosen pore size.The improved drill-in fluid was shown to possess thixotropic fluid rheology. Its additives are based solely on synthetic polymeric material for increased chemical and thermal stability. Hot-roll temperatures in excess of 355°F (180°C) were achieved with no loss in rheological properties.
Maximizing Hole Enlargement While Drilling (HEWD) Performance With State-of-the-art BHA Dynamic Analysis Program and Operation Road Map
Authors: Algu D. R. , Denham Waitus , Nelson Gail , Tang Wei , Compton Molly T. , Courville David F. , Fitzmorris David L. 
Published: September 2008

Abstract
Hole enlargement while drilling (HEWD) is an important technique in both deepwater and onshore drilling. Drilling interbedded formations is a difficult HEWD application. Two extreme cases can occur. One case is when the reamer drills in soft formation while the bit is in a harder formation. The other more difficult situation is when the reamer is in a hard formation while the bit drills ahead in soft formation. The latter creates an enormous challenge for the reamer to drill the harder formation without inducing large lateral and torsional vibrations which is detrimental to the reamer and other BHA components. An overall HEWD operating parameter management approach can greatly reduce probabilities of tool damage and unnecessary tripping while dramatically reducing drilling costs.
A state-of-the-art BHA dynamic analysis program that allows modeling the reamer and bit in different formations plays a vital role in the overall HEWD management process. Before any planned HEWD operation, various possible operating scenarios can be virtually simulated through the BHA dynamic analysis program to evaluate the effect on BHA components of lateral and torsional vibrations. An optimized BHA configuration can be specified through these analyses and a set of optimal operating parameters for the chosen BHA can be developed.
This paper presents an excellent case study of HEWD through severely depleted interbedded formations in the Gulf of Mexico. Previous offset wells had required multiple runs to HEWD this section due to reamer cutting structure damage. Models were constructed to compare performance with a range of BHA, WOB/WOR and RPM combinations. A set of optimal operating parameters and a road map were established for managing these parameters on the rig. Most importantly, the analyses recommended operating conditions that were substantially different from the accepted HEWD operation of increasing weight on bit (WOB) in harder formations. The analyses indicate that overall BHA performance was dramatically affected by weight on reamer (WOR). With a small sacrifice of ROP in the harder, more abrasive formations the HEWD system can effectively drill through the entire section without tripping due to component failure. This approach achieved excellent overall cost effective performance saving the operator $1.89 million on an offset well.
Knowledge Management and Preparing for the Big Crew Change—A Fresh Approach
Authors: Kulakofsky David 
Published: September 2008

Abstract
Achieving consistent long-term zonal isolation via the hydraulic cementing process is a worldwide challenge that can benefit from experienced personnel. Each well type presents a specific set of complexities that require assessment and technical problem solving. Under today's massive industry-wide hiring blitz, an ever increasing portion of the work is being done by personnel with fewer years of experience than in recent decades. It is critical that a methodology be made available to transfer best practices down to the frontline and capture the knowledge of experienced personnel likely to retire in the next 10 years. While many of the associated operational tasks have well-documented procedures, the engineering and job design have aspects that have not benefited from the same degree of documentation to capture step-by-step guidelines or process mapping.
In an effort to secure for future reference all of the industry's current cementing job design and engineering knowledge and best practices, an entire library of technical playbooks has been created. While these playbooks specifically address issues related to cementing, the methodology for securing and referencing the expertise is equally applicable to the industry's other specialties. This paper contains a discussion of the methodology used to develop these playbooks, as well as examples of how they are used to increase both reliability and innovation, including their applicability to the industry as a whole.
The Benefits of Safety Card Automation in Behavior-Based Safety Systems
Authors: Kaminski Donald , Graf Jake , Fortune Dan , Toups John 
Published: September 2008

Abstract
One of the more significant problems with Behavior Based Safety (BBS) Observation systems is the management of information, including the input of data into a repository, and the extraction of tangible outputs and actionable issues in a timely manner. BJ Services Company and JW Toups, Inc. have collaborated on the development, testing and implementation of a scannable system that captures BBS observations and interventions. The system allows the end user to scan hundreds of BBS cards and run reports on leading indicators within days. The system outputs trending data in an easy-to-read pie chart format for review in safety meetings and posting on bulletin boards. The scanning aspect of the system reduces both input time and administrative cost. A cost reduction of as much as 40% can be realized depending on current input techniques. In addition, the system automates the notification of management when the person completing the observation indicates management needs to take action. Management is then able to react more quickly and with a focus on the issues that really matter. This quick response increases employee participation in the BBS process. The pilot location reported an increase in participation of 30% when comparing subsequent quarters. The system solves the issue of managing information by providing management the tools to determine leading indicators and actionable items quickly and efficiently that, when addressed, make a safer workplace.
Advanced Cement Systems Used to Improve Geothermal Well Reliability in Java
Authors: Ravi K. , Fukuzawa M. , Hunter W. J. , Noerdin A. Isvan 
Published: September 2008

Abstract
An operator developing a geothermal field to generate and provide electricity in Indonesia focused on minimizing the potential for failure of planned wells throughout the expected field life. One of the main areas where this effort was directed was in the design and execution of primary cementing jobs during well construction. Wells drilled and completed earlier, in Phase I, were found to suffer from various wellbore integrity issues. Inspection log data and cement job records from existing wells suggest the zonal isolation problems experienced on earlier wells may have been related to (1) structural failure of the conventional cement sheaths used and/or (2) ineffective cement slurry placement caused by poor hole cleaning of the drilling fluid and/or (3) ineffective removal of drill cuttings from the well during the hole cleaning.
Structural damage to the cement sheath can sometimes be in the form of debonding at the casing, formation interfaces, cement sheath cracking, and/or compressive shear. The damage can be caused by stresses on the cement sheath brought on by well events such as cement hydration, well completion, and steam production. These events change the temperature and pressure under which the cement slurry is placed and cured. If these changes are severe, the cement sheath may be damaged, leading to zonal isolation failure.
After detailed analysis, and by using an integrated design approach to effectively address the challenges identified, it was decided to use innovative elastic cement systems incorporating various mechanical property enhancement additives expected to withstand the predicted well operations with less possibility of failure than conventional cements.
These advanced cement systems were placed in the planned development using conventional cementing equipment. Industry-recognized best practices were also used to maximize mud displacement and enhance hole cleaning. These wells were steamed, and no wellbore integrity issues have been reported. Additional benefits observed while using the advanced cement systems in these applications include a reduction in lost circulation and significantly reduced wellhead growth.
Pseudo–Compositional Model for the Calculation of Liquid Viscosity in Oil Production Systems
Authors: Bergman David F. , Sutton Robert P. , Zaghloul José 
Published: September 2008

AbstractModern numerical simulators can couple models to represent the behavior of reservoir, wells and surface facilities. This has created a need for a method to calculate viscosity over a wide range of compositions, pressures, and temperatures. Current compositional viscosity models cannot predict viscosities over these wide ranges. Bergman and Sutton (2006, 2007a, 2007b) published three new correlations that matched viscosity changes with temperature and pressure. Their correlations were based on typical black-oil model parameters; among them solution gas-oil ratio, mole weight and API gravity of the stock tank oil. These parameters change with liquid composition. This paper provides a method for estimating these parameters from liquid composition for calculating viscosity using the Bergman-Sutton correlations. Comparisons with other compositional viscosity models were made to show the new model's improved behavior.
Non-Iterative Phase Behavior Model with Application to Surfactant Flooding and Limited Compositional Simulation
Authors: Roshanfekr M. , Li Y. , Johns R. T. 
Published: September 2008

Abstract
Hand's method is typically used to empirically calculate the equilibrium compositions for ternary systems between two liquid phases. Oil field application of Hand's method is generally limited to surfactant phase behavior with oil and brine, primarily because the excess oil and brine phases are nearly immiscible. Hand's method is not accurate to represent liquid-vapor equilibrium, especially as oil and gas become miscible. It also requires iterations, which means that convergence can be slow depending on the initial guess.
In this paper, we present a new empirical phase behavior model to replace Hand's method. The new method is faster and more accurate, and applicable for both surfactant phase behavior and liquid-vapor equilibrium. The new approach is noniterative and always finds a tie line or its extension even for the limiting tie line at the critical point. Our approach transforms tie lines to a new compositional space, where all tie lines become parallel. Equilibrium compositions are then easily determined in the transformed space. Besides improved accuracy and robustness, the flash calculations for ternary systems show that the new method is up to 100 times faster than conventional calculations using a cubic equations-of-state (EOS), and seven times faster than Hand's method. When incorporated in a compositional simulator, the new method reduces flash calculation time to nearly zero compared to the solution of the pressure/compositional equations. Thus, speedup is proportional to the fraction of time occupied by flash calculations within the simulator. For example, if flash calculations are 50% of total simulation time, speedup is nearly a factor of two using the new approach. This approach is ideally suited for fast recovery estimations for miscible gas floods, and fills the gap between standard or modified black-oil models and fully compositional simulations.
Development and Installation of a Triple Wellhead on the Britannia Platform
Authors: Matheson A. Elizabeth , Tayler Peter , Nash R. Scott , McAuley John 
Published: September 2008

Abstract
The Britannia field is a gas condensate accumulation in the U.K. Central North Sea. The Britannia platform has 36 slots and was initially developed by single wells drilled from 25 of those slots. In 2003 the first of 8 double wellheads was installed enabling two wells to be drilled from each slot (16 wells). In September 2006 the first triple wellhead was installed and three 13⅜ in casings were batch set at 3650 ft TVD. During 2007, three production wells were successfully drilled and completed from this triple wellhead.
This paper discusses the development and installation of the triple wellhead system utilising the experience and lessons learnt from the double wellhead system. Essential to the triple design was that there should be no reduction in hole/casing size, well step out, tubing size or Christmas tree bore size and therefore no drilling or production restrictions for a triple well compared with other wells on the platform. A design/implementation team was set up with operator personnel, contractor personnel and various service providers. This paper discusses the challenges faced by the team – design of the wellhead and tree, running 38 in x 46 in flush joint conductor, running the internal well splitter system on 5½ in tubing and checking its alignment, running of the casing starter head from the production deck, the modelling and clash checking work done to ensure that the wellheads, trees and flowlines would fit in the space available and having the ability to perform wireline work on one or two of the triple wells when drilling on another.
The design objectives were all met and in early 2007 an extended reach well measuring 21580 ft with a step out of 16300 ft was the first well drilled and completed from the triple slot. The second well was a 14100 ft infill well and the third well in the triple slot was completed in November 2007 with a measured depth of 17680 ft MD and a step out of 9970 ft.
Magnetic Resonance in Chalk Horizontal Well Logged With LWD
Authors: Thorsen Arve K. , Eiane Tor , Thern Holger , Hughes Baker , Fristad Paal , Williams Stephen 
Published: September 2008

Abstract
This paper describes geological and petrophysical evaluation of a new structure of a mature field to evaluate the reservoir potential in un-produced reservoir zones. The well was drilled in a carbonate with variations in rock quality and with minor sub-faulting occurring. Gamma, Resistivity, Density, Neutron, and Image services were used in the horizontal part of the well in addition to Magnetic Resonance. To achieve the best possible real-time wellbore placement, reservoir navigation and continuous follow-up on the horizontal log interpretation was performed during drilling.
For the first time a low gradient Magnetic Resonance (MR) while drilling technology was deployed in a virgin carbonate horizontal well on the Norwegian Continental Shelf. The MR Service was run to obtain porosities (incl. partitioning of movable and bound fluids), HC saturations, and permeability estimates. Fluid saturations based on traditional methods and the MR were evaluated and compared by core data, enhancing the understanding of the measurement and the reservoir. For post-processing the MR data were integrated and interpreted together with the other measurements performed in the well delivering an accurate and consistent reservoir description.
First part of the horizontal part of the well was drilled with conductive drilling fluid and the latter part with non-conductive drilling fluid. Lab measurements for the two mud filtrates were performed to understand the influence of the two different drilling fluid types on the MR measurements. In the absence of oil based mud filtrate invasion, the MR data show better agreement with saturations from core confirming the quality and reliability of the MR data.
Comparison of the MR T2 distribution and volumetric with image data indicates that even fine variations in rock quality and lithology are reliably resolved by the MR data. Prior to logging, old core data was used to refine the constants used in the Timur-Coates MR permeability equation. MR permeability showed changes in reservoir quality. Values will be calibrated when Timur-Coates constants are derived from the core plugs from this well.