bluuebunny/crossref_metadata_2025_split huggingface dataset:
Timestep Selection During Streamline Simulation via Transverse Flux Correction
Authors: Osako Ichiro , Datta-Gupta Akhil , King Michael J. 
Published: December 2007

Abstract
Streamline simulators have received increased attention because of their ability to effectively handle multimillion cell detailed geologic models and large simulation models. The efficiency of streamline simulation has relied primarily on their ability to take large time steps with fewer pressure solutions within an IMPES formulation. However, unlike conventional finite-difference simulators, no clear guidelines are currently available for the choice of time step for pressure and velocity updates. This has remained largely an uncontrolled approximation, either managed by engineering judgment, or by potentially time-consuming time step size sensitivity studies early in a project. This is clearly related to the lack of understanding of numerical stability and to the lack of error estimates during the solution.
We propose a novel approach for time step selection during streamline simulation that is based on three elements. First, we reformulate the equations to be solved by a streamline simulator to include all of the three-dimensional flux terms – both aligned with and transverse to the flow directions. These transverse flux terms are totally neglected within the existing streamline simulation formulations. Second, we propose a simple grid-based corrector algorithm to update the saturation to account for the transverse flux. Third, we provide a discrete CFL (Courant-Fredrich-Levy) formulation for the corrector step that leads to a mechanism to ensure numerical stability via the choice of a stable time step for pressure updates. This discrete CFL formulation now provides us with the same tools for time step control as are available within conventional reservoir simulators.
We demonstrate the validity and utility of our approach using a series of numerical experiments in homogeneous and heterogeneous !4 five-spot patterns at various mobility ratios. For these numerical experiments, we pay particular attention to favorable mobility ratio displacements, as they are known to be challenging to streamline simulation. Our results clearly demonstrate the impact of the transverse flux correction on the accuracy of the solution and on the appropriate choice of time step, across a range of mobility ratios. The proposed approach eliminates much of the subjectivity associated with streamline simulation, and provides a basis for automatic control of pressure time step within full field streamline applications.
Stabilized Finite Element Methods for Coupled Geomechanics – Reservoir Flow Simulations
Authors: Wan J. , Durlofsky L. J. , Hughes T. J. R. , Aziz K. 
Published: December 2007

Abstract
Coupled geomechanical-fluid flow models are needed to account for rock deformation resulting from flow-induced pressure changes in stress sensitive reservoirs. There are, however, issues of numerical stability that must be addressed before these coupled models can be used reliably. Specifically, it is known that standard procedures can lead to pressure oscillations as a result of the violation of the Babuška-Brezzi (B-B) condition, which requires unequal order interpolation of the displacement and pore-pressure variables. In this paper, a number of different types of coupled models are considered. A novel finite element method is developed to circumvent the B-B condition. The method applies a stabilized finite element technique to solve the force balance and pressure equations along with a finite volume method to solve the remaining component mass balance equations. All of the equations are solved in a fully coupled fashion. This method is compared with fully coupled and iteratively coupled models developed using non-stabilized finite elements for the force balance with finite volume methods for all of the component mass balance equations. These comparisons demonstrate that all methods perform reliably on homogeneous reservoirs over long time scales. The stabilized method is shown to provide improved stability at early times and for reservoirs with very low permeability barriers.
Integrated Optimization for Rate Allocation in Reservoir Simulation
Authors: Davidson Jeffrey E. , Beckner Bret L. 
Published: December 2007

Abstract
When using a reservoir simulator to predict future field production, one must establish operating rules and procedures to manage wells and surface facilities. In EMpower™, Sequential Quadratic Programming (SQP) methods are used to set well rates in a facility network of a reservoir simulator so that production objectives are maximized subject to constraints on pressures, flow rates and stream compositions. Actions taken for infeasible conditions are discussed. Black-oil and compositional examples are given.
New PDC Design Process Solves Challenging Directional Application in Abu Dhabi Onshore Fields
Authors: Al-Suwaidi Abdullah S. , Soliman Ahmed Abou , Klink Zeinoun , Isbell Matt , Dykstra Mark , Jones Christopher 
Published: December 2007

Abstract
Roller cone bits have dominated the 8–1/2" steerable application in Abu Dhabi due to their proficient steerability, consistently achieving the required build rates in the soft Nahr Umr shale. In the vertical section, PDC bits often achieve up to four times the penetration rates of TCI bits. However, directional performance when using PDC bits to build angle was compromised by fluctuations in reactive torque resulting in poor tool face control and inconsistent build up rates. The overall result was poor penetration rate and performance compared to roller cone bits. The operator and a service company utilized a new design process and cross functional team approach to aggressively seek new steerable PDC technology to drill the curved section with controllable torque response and consistent directional behavior while achieving the full penetration rate advantage of PDC bits. This process was complemented by the Well Delivery Limit process (WDL) that was already established by the operator that focused on delivering high value wells with significantly reduced costs. The team analyzed the drilling operations from virtually every perspective using numerical models, laboratory drilling tests, and field testing. The key to the PDC solution was the team process that identified the relevant drilling problems and performance requirements in order to develop the needed technology. After 30 bit runs from November 2001 to June 2002, the team reduced drilling costs by $44.26 per foot for a total savings of $3,792,367 over 85,682 ft and 2,386 drilling hours. The average ROP for the section doubled from 18 ft/hr with TCI bits to 36 ft/hr. The current ROP record stands at 60 ft/hr over a 3,169 ft interval.
New, Stable PDC Technology Significantly Reduces Hard Rock Cost Per Foot
Authors: Schell Edward J. , Phillippi Duane , Fabian Robert T. 
Published: December 2007

Abstract
Historically, the hardest and most abrasive rock formations, such as the Travis Peak, Hosston, and Bossier Sands areas of East Texas and North Louisiana, were drilled almost exclusively by roller-cone insert bits. With some exceptions, the only polycrystalline diamond compact (PDC) runs were small-diameter holes where the formation was predominantly comprised of shale and limestone. Significant advances in design and cutter technology in PDC bits during the past 5–10 years have made it possible for PDC to be used more frequently on the fringes of these hard rock intervals.
Combining advanced PDC bit designs with state-of-the-art cutter technology has opened up many new applications for PDC bits that were once only appropriate for IADC Series 6, 7, and 8 insert drill bits. Because of this new technology, PDC has become a practical alternative for drilling hard rock, providing a significant reduction in cost per foot. Combining new, highly abrasion-resistant PDC cutters with competent stable bit designs that provide both low torque and dynamically stable characteristics was the key to this development.
Several case histories of hard rock drilling using PDC bits will be discussed in this paper, illustrating the reduction in costs. These case histories demonstrate, through descriptions of trial and error, the problems associated with these new PDC applications and how they were overcome.
Gulf of Mexico Performance Fluids Management Implementation – Seven-Step Process
Authors: Rojas J. C. , Schonacher D. , Hudson C. , Gharst J. , Paiuk B. , Billon B. 
Published: December 2007

Abstract
BP's Gulf of Mexico (GoM) Operations have determined that the reduction of oil-on-cuttings (OOC) from 14% to less than 6.9% would provide the best opportunity to minimize the environmental impact of drilled cuttings discharge base on currently available technologies. Meeting the GoM NPDES environmental regulations, while simultaneously improving drilling performance drove the implementation of a Performance Fluids Management (PFM) process. Created within BP, PFM is a management process that integrates fluids and waste management. The new GoM cuttings discharge regulation (max 6.9% oil on cuttings) was met without adversely impacting drilling operations, while also reducing fluid cost by 8% ($3.5 MM) in 2001.
This paper discusses the development and application of the PFM process. The authors will present the key components of PFM, which include implementation of a common format for fluid management programs, end-of-well recaps, a weekly PFM report capturing agreed upon performance targets, the PFM audit process, skill assessment for fluids and PFM engineers, and a model to predict accurate PFM cost/volumes generated. The PFM process has been implemented in Colombia, Bolivia and Argentina where it delivered similar savings. The process currently is being implemented in Trinidad. The process is applicable to wells in excess of $7–10 million total cost. The potential fluid cost reduction associated with a global PFM implementation will be around 10–15% ($20–25 million/year).
Multistation Analysis and Geomagnetic Referencing Significantly Improve Magnetic Survey Results
Authors: Lowdon R. M. , Chia C. R. 
Published: December 2007

Abstract
Improvements in the quality of wellbore directional surveys using multistation analysis and geomagnetic referencing are demonstrated, with case studies to illustrate the benefits to drilling projects. Multistation analysis is a technique that provides compensation for drillstring magnetic interference. The benefits of multistation analysis can be further improved when used in conjunction with geomagnetic referencing, which takes account of localized crustal effects in the earth's magnetic field.
In recent years these improved magnetic surveying techniques have gained increased industry acceptance. Their practical application is delivering the capability to reach tighter drilling targets, and in some circumstances to dispense with the need to run gyro surveys. These techniques are providing tangible and cost saving benefits to help meet the demanding technical and economic needs of these projects.
A series of well profiles for wells drilled on projects that use these techniques are presented, each of which use individually mapped local crustal magnetic field models and different drilling assembly configurations. Treatment of each of the major magnetic surveying error sources is discussed, and the effect on surveyed well position when compared with independent overlapping gyro surveys is presented.
The benefits from this real-time drilling surveying process also demonstrate the value of the "drilling correction" as a means of drilling more accurately to plan, with a reduced need for correction runs, or post-drilling changes to the planned well trajectory.
Casing Drilling Activity Expands in South Texas
Authors: Fontenot Kyle , Highnote Joe , Warren Tommy , Houtchens Bruce 
Published: December 2007

Abstract
Conoco has had a sustained, multi-rig, development program in the Lobo field of South Texas since the mid-1990's. Drilling efficiency using conventional techniques has improved to the point where additional gains are difficult to achieve. Drilling with casing was implemented as a potential way to provide a step change to drilling performance in this mature field. The Casing Drilling* process has proven to significantly reduce the in-hole trouble time below the low value that was already obtained and has demonstrated the ability to further reduce drilling costs.
The first two phases of the Lobo Casing Drilling program were conducted with a dual-purpose (Casing Drilling/conventional drilling) rig. After drilling 22 wells, the Lobo Casing Drilling program is being expanded by replacing this rig with three new Casing Drilling rigs designed to further optimize Casing Drilling performance. The first of these rigs is on location and the other two will begin operations by the end of 2002.
Maintaining Well Productivity through Deployment of a Gas Lift Scale Inhibitor: Laboratory and Field Challenges
Authors: Fleming N. , Stokkan J. A. , Mathisen A. M. , Ramstad K. , Tydal T. 
Published: December 2007

Abstract
This paper will focus on the laboratory and field challenges of maintaining productivity in a North Sea well through scale inhibitor deployment via gas lift. Calcium carbonate scale formation commonly occurs during early production of formation water and in this particular well was detected on the downhole safety valve and upper tubing. Several scale management options were considered, however, that considered most likely to succeed was inhibitor injection via the gas lift system.
An extensive laboratory evaluation under the North Sea field downhole conditions was undertaken in order to qualify a suitable scale inhibitor/solvent package. While the identification of a scale inhibitor capable of controlling calcium carbonate was relatively simple, the combination of an aqueous based inhibitor with a suitable solvent package proved challenging. The initial product development stage was focused towards identifying compatible blends of various types of scale inhibitors (phosphonates, polymers and vinyl sulphonate copolymers) with different solvent and solvent mixtures. An essential aspect of the formulation design was to minimise the potential for volatile loss from the product to the dry injection gas.
Several candidate scale inhibitor/solvent packages were put through a rigorous laboratory evaluation programme under the harshest possible conditions likely to be experienced in the field. From this initial review products were identified as passing pre-defined criteria and showed good environmental qualities with very low viscosities (5cP or less at ambient temperature) before and after volatile loss and had very low corrosivity (0.01mm/y). In addition, the chemicals displayed complete compatibility at concentrations in excess of 50% with the completion fluid, formation water and completion elastomers, and controlled calcium carbonate scaling at a relatively low concentration.
The final part of the paper will provide details of the field deployment experiences and challenges of the gas lift scale inhibitors developed.
Fighting Naphthenate Deposition at the Heidrun Field
Authors: Vindstad Jens Emil , Bye Arne S. , Grande Knut V. , Hustad Britt M. , Hustvedt Egil , Nergård Bjørn 
Published: December 2007

Abstract
At the Statoil-operated Heidrun-field in the Norwegian Sea, naphthenate deposits were first observed during a maintenance shutdown in September 1996. Thereafter the problem increased, and by the end of 1997 it was recognised as a constant threat against continuous production. The present paper describes both the short-term measures taken to gain control of the problem in the early days, and the quest for a more elegant long-term solution. Statoil is continuously working to increase its fundamental understanding of the naphthenate problems and to improve the naphthenate inhibitors used at the Heidrun field.
The Interaction of Flow and Reactions in Porous Media
Authors: Woods A W , Jupp T E , Richardson C N 
Published: December 2007

Abstract
As water migrates through porous rock, any changes in pressure or temperature, as well as changes in fluid composition, may lead to changes in the solubility of dissolved minerals. We examine the reactions which may develop in such a system, following the injection of water of one temperature and composition into a reservoir with different temperature and equilibrium composition. We examine the structure of pressure, temperature and compositionally induced reactions.
Development of a Suitable CaCO3 Scale Inhibitor System for use in Ultrahigh Temperature and Pressure Wells
Authors: Wylde J. J. , McKay S. F. , Falla M. 
Published: December 2007

Abstract
This paper reports a case study on the selection of a HP/HT/HS scale inhibitor for CaCO3 precipitation in the ultrahigh temperature and pressure environment experienced in the TotalFinaElf Elgin-Franklin assets. The paper will outline the scale management, inhibitor selection and deployment strategies adopted for scale control in this extremely harsh environment. The downhole temperature in these wells can be up to 200ºC and pressures can exceed 16000 psi. Problems are further enhanced by large decreases in pressure over relatively short changes in well depth. The literature is scant on studies performed at these conditions and a thorough screening of a wide range of scale inhibitor products and deployment techniques is an essential asset to the continued exploitation of very harsh well conditions.
A new, upgraded scale prediction routine has shown that CaCO3 precipitation will occur over the whole range of reservoir conditions. A wide range of scale inhibitor chemistries including sulphonated polymers, phosphonates and some novel development products have been screened using four industry standard techniques. Thermal ageing revealed any instability caused by thermal degredation of the inhibitor molecule and jar test compatibility experiments performed at field temperature showed chemical incompatibilities with field brines. Dynamic scaling loop experiments were performed on not only the fresh inhibitor chemistries but also on thermally aged samples. The thermally aged samples were also analysed spectroscopically to identify any breakdown products and mechanisms. Finally coreflood experimentation was used to highlight inhibitor return profiles over a simulated squeeze treatment and to look for any formation damage that may have occurred.
Critical Success Factors for Technology Transfer: Sharing a Perspective
Authors: Badruzzaman Ahmed 
Published: December 2007

Abstract
The paper describes three examples from the author's experience of technology transfer in the E&P industry and examines a number of critical elements, beyond those normally found in the literature, that need to be accounted for to bring about a successful and durable transfer of a technology. These include meticulous planning, determination of appropriateness, recipient buy-in, an early demonstration of benefits, at least a nascent technology base and awareness, continuous mentoring and monitoring, and finally evolution into a culture of technology utilization and management.
The Different Condensate Gas Recovery Using Gas Oil Permeability and Gas Condensate Permeability Curve
Authors: Chang Su , Ping Guo , Li Shilun , Guo Xiao , Sun Liangtian , Sun Fengjing 
Published: December 2007

Abstract
Till now, condensate reservoir engineers in China used substitute permeability curve, measured by unsteady-state method using model oil (kerosene etc.) and model gas (nitrogen etc.) system, to be basic input curve in numerical simulation and well testing. The typical interfacial tension of the model fluid system is about 30mN/m, which is much higher than true condensate system. The objectives of the work presented in this paper, were measuring relative permeability of condensate system and model fluid system, comparing their differences and resultant condensate gas recovery differences. The experiments employed true condensate system and formation core and were based on measurement of basic core and fluid properties, preliminary compositional simulation of fluid behavior. The measurements showed that the relative permeability curves to the gas condensate system are quite different to curves of model gas/oil system, and a relative permeability rate effect for both condensate oil and gas was observed, with the relative permeability of both phases increasing with an increase in flow rate. The CMG one-dimensional radial simulation results showed that the resultant condensate oil and gas recovery of condensate gas oil permeability curves are both largely different from those of model gas/oil permeability curves. The study highlights the need to use condensing fluids when measuring gas condensate relative permeability.
Identification of Initial Gas Net-Pay in Deltaic Reservoirs Using Wireline Acoustic Measurements
Authors: Larrouquet F. , Gautama A. , Moinard L. 
Published: December 2007

Abstract
In the Mahakam delta in East Kalimantan, TotalFinaElf E&P Indonésie operates fields with numerous multi-layer reservoirs deposited within a deltaic environment. Formation waters in these reservoirs have very low salinities, which vary with depth and from reservoir to reservoir. When a field is in production, the evaluation and update of initial hydrocarbon net-pay is made more difficult by depletion and fluid level changes, which are related to channel reservoirs connectivity, both laterally and vertically. A new method has been developed, based on acoustic measurements, to help identify the original gas net-pay.
This method uses the fact that compressional acoustic waves travel slower in gas than in liquid whereas shear waves are not affected by fluids in the pore space. An empirical correlation is established between Vp/Vs ratio and shear slowness in known liquid-bearing sands. This correlation is used to predict Vp/Vs over the whole logged interval. A large difference between predicted and measured Vp/Vs indicates the presence of gas. Since gas is very compressible, the effect is noticeable even at very low gas saturations, i.e., in gas reservoirs that have already been depleted, or even swept by water.
The method was first tried in a mature oil field in order to distinguish gas from liquid and gave encouraging results. It was then applied in a gas field where a 3000-meter interval of dipole sonic log had been recorded in one well. Fluid status identified by this method was crosschecked against all other data (wireline logs, mud logs, wireline fluid samples) and against the geological model. The results helped confirm (or revise) the model, which, in turn, improves mapping, material balance calculations and optimization of production.
Based on numerous examples, the conclusion is that very good results are obtained in clean sands, especially where known water and gas bearing intervals are available for calibration. The article also states the limitations of the method, which can give ambiguous results in very shaly reservoirs and also fails in deep reservoirs where porosity falls significantly below 15 percent.