bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Consistent Approach Toward Reservoir Simulation at Different Time Scales
Authors: Nikolaou M. , Cullick A. S. , Saputelli L. , Mijares G. , Sankaran S. , Reis L. 
Published: December 2007

Abstract
Reservoir simulation has become the de facto design and analysis tool to plan, develop, and manage oil and gas assets. With increasing complexity of flow networks and advanced recovery mechanisms in the fields, the model description and features of the reservoir simulator have also been progressively advancing.
The goal of a single, evolving, life-cycle model for oil and gas assets has many benefits for effective and efficient field development and exploitation. However, the size and complexity of the reservoir models often require characterization at several resolutions, thus ranging from full field strategic models to short range operational models. Full field strategic models can be used to evaluate various production scenarios and development strategies and to estimate future drilling and facilities requirements. Short range operational models concentrate on issues such as rate requirements, production decline analysis, etc. However, the approach to integrate and maintain these separate reservoir models while describing the same field is often ad hoc and many times, inconsistent.
This paper describes a new methodology for enhanced and effective use of reservoir simulation. Specifically, the application of a new method is presented to consistently integrate the full field strategic models and the short range operational models using a parametric system identification approach. The measurements from the field are used to continuously update the short range operational models over a moving time horizon, while simultaneously preparing the data for a history match of the full-field, strategic model. This hierarchical model structure at different scales avoids frequent and costly history-match runs of the larger strategic models without compromising on short term accuracy, for example, those required by production optimization. In addition, the hierarchical model structure improves effectiveness and efficiency in carrying out the simulation objectives. A case study of a full-field performance is presented to highlight the benefits of the method.
Risk Minimization by the Use of Failure Mode Analysis in the Qualification of New Technology, Applied to Intelligent Field Systems
Authors: Hother J. 
Published: December 2007

Abstract
Industry has recognised the value of failure mode analysis, which is being used on a rapidly expanding scale, to minimise risk, increase the probability of success and target product development spend to optimise life cycle costs for new technology, especially when applied to upstream projects. This paper illustrates best practice in failure mode analysis for oil and gas projects, by using recent case studies addressing intelligent well completions, and sand control including expandable technologies. The paper explores how these methods are applied to larger integrated systems, such as intelligent fields.
The paper highlights how methods originating in the defence and aerospace industries are adapted for the specific requirements of oil and gas projects, and identifying the key issues from recent project experience, namely – Complete system approachFunctional requirementsLife-cycle phasesTraceabilityCost of failureDirectly usable results that are fed back into the design, development and implementation processes.
-and it shows how the methods suit the analysis of large complex systems, including intelligent fields.
The paper shows how versatile the method is, identifying the different roles in which this type of analysis is proving valuable, namely – Business case – feasibility study of development optionsDesign optimizationQualificationReliability improvementVendor pre-selection
… and it shows how the method can be used to step beyond supply-chain conflicts and avoid commercial issues distracting from productive technical progress.
Experimental Confirmation of Analytical Composition Routes in Three-Phase Partially Miscible Flow
Authors: LaForce T. , Cinar Y. , Johns R. T. , Orr F. M. 
Published: December 2007

Abstract
In this paper effluent data from laboratory experiments are compared with analytical composition routes and profiles for three-phase partially miscible flow of three-component mixtures. Core flood experiments were run in vertical glass bead packs to achieve approximately one-dimensional displacements with stable displacement fronts. The displacements employed in this study include modest effects of dispersion, but dispersion does not substantially alter the composition routes.
Complex analytical composition routes are developed by the method of characteristics (MOC) for one-dimensional, dispersion-free flow where up to three partially miscible flowing phases may be present. The exponents used in the relative permeability model were obtained by fitting profiles from one drainage (oil injection) and one imbibition (water/alcohol injection) displacement. The resulting parameters were used to construct the analytical solutions for the remaining displacements. Development of the analytical solutions to Riemann problems is outlined.
Different parameters are obtained for the imbibition and drainage experiments, indicating that hysteresis occurs in the experiments. Comparison of the experimental results with the analytical solutions shows that the mathematical model captures the essential features of the experimental displacements. In the cases in which the analytical solutions fail to model accurately the physical displacements, the effect of simplifying assumptions in the model are examined.
Control of a Displacement Front in Potential Flow Using Flow-Rate Partition
Authors: Fyrozjaee H. , Yortsos Y. C. 
Published: December 2007

Abstract
We consider the problem of the control of a displacement front in a porous medium, via flow-rate partition in a well. We assume that the flow is potential and that the displacement is at a unit mobility ratio. These assumptions are for mathematical convenience only and can be relaxed. They allow, however, significant insight into the problem. The specific question we address is how to partition the flow rate within the injection well, so that the induced displacement front can be steered according to pre-determined dynamics.
When the reservoir is homogeneous and isotropic, we derive an integral equation in an analytical form, the solution of which determines the desired injection rate profile. We provide illustrative applications. A similar approach applies for an anisotropic or a heterogeneous system, except that the kernel in the integral equation must be determined numerically. This can be obtained by repeated calculations of the Green's function in a heterogeneous system or a modified two well system.
For the solution of the integral (Fredholm) equation, a regularization technique is necessary. However, it is found that numerical instabilities do develop, even with the use of regularization, for later times, when tranverse cross-flow is large. Conversely, the instabilities diminish with a more stratified structure.
The results find applications to the rapidly emerging field of smart wells and the optimization of displacement problems in oil reservoirs using flow rate control.
Proppant Placement Using Reverse-Hybrid Fracs
Authors: Liu Y. , Gadde P. B. , Sharma M. M. 
Published: December 2007

Abstract
In conventional gel fracturing treatments, the damage induced by the gel can have a significant impact on well performance, particularly in low permeability gas formations. Slick-water fracs have been shown to be more successful in some tight gas formations because of reduced gel damage and limited height growth. Proppant placement is a major concern in water fracs. Hybrid water-fracs (using slick water as the pad fluid and gel to place the proppant) provide some improvements to the performance of water-fracs.
This paper proposes a new method, reverse-hybrid fracs (RHF), for the efficient placement of proppant deep into created fractures while minimizing gel induced damage. Experiments were conducted in a simulated fracture (slot cell) to study the transport of proppant. Slick-water was injected first into the slot, followed by gel. Finally slick water containing proppant was injected to displace the gel. The water that carried the proppant, quickly formed viscous fingers through the gel. The gel was observed to form long thin layers which effectively hindered proppant settling and helped transport the proppant further into the slot. This resulted in the formation of proppant packs above the gel layers.
In this paper, experimental results are presented to show how the gel layers distribute in the slot and how proppant distribution is affected by the gel layers. A transparent cell made up of rough walls was set up to investigate the effect of fracture wall roughness. The effects of fluid viscosity ratio, fracture wall roughness and gel pad volume were investigated. Based on the experiments and scaling relations, recommendations are made for the pumping sequence and the size of the gel and slick water stages in reverse hybrid fracture treatments.
This method of proppant placement requires less gel than conventional gel-fracs and smaller pump horsepower than water-fracs. Other advantages include: less gel damage to the proppant pack and less penetration of the pad fluid into the formation resulting in shorter cleanup time following fracture treatment.
Comparative Evaluation of a New MMP Determination Technique
Authors: Ayirala S. C. , Rao D. N. 
Published: December 2007

Abstract
A new experimental technique of vanishing interfacial tension (VIT) has been reported in recent literature for quick and cost-effective determination of gas-oil miscibility. However, this technique has been criticized due to the perceived absence of compositional path specification as well as for lack of the confirmation against standard gas-oil systems. In this paper, we address these concerns by conducting interfacial tension measurements at elevated pressures and temperatures in two standard gas-oil systems and at varying molar compositions of gas and oil in feed mixtures. The two standard gas-oil systems used are: CO2 against n-decane at 100°F, and CO2 against live decane consisting of 25 mole% methane, 30 mole% n-butane and 45 mole% n-decane at 160°F. In addition to the pendent drop technique, the capillary rise technique has been adapted and successfully used for low gas-oil interfacial tension measurements at elevated pressures and temperatures.
Though gas-oil ratio was found to have an impact on mass transfer rates, the interfacial tension between gas and oil was unaffected as the fluid phases approached equilibrium. This indicates the compositional path independence of gas-oil interfacial tensions measured at near-equilibrium and miscibilities determined using the VIT technique. The minimum miscibility pressures determined using the VIT technique matched well (within 4-8%) with the reported slim-tube miscibilities for both the standard gas-oil systems used. This paper relates first- and multiple-contact miscibility development in gas injection displacement processes to laboratory gas-oil interfacial tension measurements. We also found that the dynamic behavior of gas-oil interfacial tension reflects the multi-stage contact between gas and oil that occurs in the reservoir displacement processes. Thus this experimental study demonstrates the indisputable interrelationship between interfacial tension and miscibility and hence encourages the wide use of VIT technique for rapid and cost-effective determination of minimum miscibility pressures and enrichments in improved oil recovery applications.
High-Resolution Prediction of Enhanced Condensate Recovery Processes
Authors: Jessen K. , Gerritsen M. G. , Mallison B. T. 
Published: December 2007

Abstract
This paper investigates the accuracy of first and high-order numerical methods in simulating enhanced condensate processes in 1D, 2D and 3D. We compare the predictions of a standard single point upwind (SPU) scheme with a third-order accurate finite difference (FD) simulator based on a third order essentially non-oscillatory (ENO) flux reconstruction with matching temporal accuracy. We include physical dispersion in the mathematical model of these multi-phase multi-component systems.
The comparisons demonstrate that SPU schemes may fail to predict the formation of the mobile liquid bank at the leading edge of the displacement unless an impractical number of grid blocks is used in the simulation. In contrast, the high order FD simulator is demonstrated to accurately predict the liquid bank at much lower grid resolution providing for a more efficient simulation approach. In 2D displacement calculations with gravity, the CPU requirement by the SPU scheme was found to be more than 50 time that of the ENO scheme for a given level of accuracy. In 2D vertical cross-sections, the predicted component recovery is demonstrated to vary upwards of 8% depending on the selected numerical scheme for a given grid resolution and dispersivity. In these settings the SPU solutions converge to the ENO results upon significant grid refinement.
In 3D displacement calculations, the magnitude of the predicted condensate bank is also found to be very different depending on the selected numerical scheme. Relative to the 2D displacement calculations, condensate banking and gravity segregation is observed to have less impact on the process performance prediction due to the permeability configuration in the 3D model used here, but it could have a high impact in different settings.
We include an explicit representation of longitudinal and transverse dispersion in the porous medium to demonstrate the grid resolution required to resolve physical dispersion at a given simulation length scale, and to show that condensate banks can also form in more realistic dispersive systems. Grid refinement studies in 1D and2D demonstrate, again, that the ENO scheme outperforms the SPU scheme for a given Peclet (Pe) number. Converged solutions are obtained with the ENO scheme using a relatively small number of grid cells. In addition, we show the behavior of the two schemes for varying Peclet numbers on a fixed simulation grid. For this grid, the ENO scheme is shown to be sensitive to the Peclet number, signifying that physical dispersion is not overwhelmed by numerical diffusion. For the SPU scheme, however, the solutions are almost independent of the Peclet number which indicates that numerical diffusion dominates.
Reservoir-Conditions Laboratory Experiments of CO2 Injection into Fractured Cores
Authors: Darvish G. R. , Lindeberg E. , Holt T. , Utne S. A. , Kleppe J. 
Published: December 2007

Abstract
During CO2 injection into fractured reservoirs the overall oil recovery will be the result of the complex interplay of several mechanisms such as viscous flow, extraction by molecular diffusion and gravity drainage. In order to study the component exchange between the matrix and the fracture system during the CO2 injection, CO2 injection experiments at reservoir conditions have been carried out using 60 cm long 4.6 cm diameter composite cores from an outcrop analogue to one of the North Sea reservoir rock.
The core and core holder assembly were designed to allow a 2 mm fissure to surround the core plug simulating a fracture. Live reservoir fluid was prepared and used for saturating of the matrix system. Because of the large permeability contrast between core (4 mD) and fracture it is difficult to saturate the core by simply flooding the system with live oil. Oil would flow through the fracture and only partially saturate the core To overcome this problem a unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized with the CO2. During the experiments CO2 was injected at a low and constant rate into the fractured system. The component exchange between the oil in the matrix and CO2 in the fracture was monitored by analyzing the produced fluids. The recovery profiles and the fluid compositions were used to construct a compositional numerical model.
The results from the experiments in the long core as well as the simulation studies show the importance of the diffusion mechanism in these experiments. The results have proved that the key mechanism to recover oil from the tight matrix block was diffusion and the gravity drainage had no significant effect at the experimental conditions used.
Transport of a pH-Sensitive Polymer in Porous Media for Novel Mobility-Control Applications
Authors: Choi S. K. , Ermel Y. M. , Bryant S. L. , Huh C. , Sharma M. M. 
Published: December 2007

Abstract
Injection of a pH-sensitive polymer into a heterogeneous reservoir as a novel deep-penetrating mobility control method has been proposed earlier (Al-Anazi and Sharma 2002b). A polyelectrolyte that forms molecular-network microgels in solution is injected into high-permeability zones under acidic conditions. Upon contact with reservoir rock, the injected fluid experiences an increase in pH due to geochemical reactions between the injected fluid and carbonate and other mineral components in the rock. The pH increase swells the polymer, which drastically increases the apparent viscosity of the polymer "solution", significantly lowering the mobility of water in the high-permeability zone. For the controlled application of this novel process, the mechanisms for each of its three sub-processes need to be understood: (1) dependence of polymer viscosity on ionic (pH) conditions in the reservoir; (2) geochemical characterization of pH change in the rock; and (3) polymer microgel transport in porous media. Viscosity characterization has been reported earlier (Huh et at. 2005). The geochemical characterization and the microgel transport are reported in this paper.
For geochemical characterization, brine at pH=2 was injected into a Berea sandstone core. The pH and cation concentrations in the effluent were matched, employing our geochemical simulator, KGEOFLOW. An approximate representation of sandstone with three mineral components adequately matched the pH change during the acid-injection coreflood. For a preliminary characterization of soft microgel transport, a pure-silica sandpack at a constant pH was employed to remove any geochemical effects (i.e., no microgel swelling). From the pressure gradient data available from internal pressure taps, the permeability reduction due to polymer retention was obtained as a function of polymer structure (represented approximately by rheological parameters) and polymer concentration, and with addition of surfactant. The retention can be explained by adsorption on the silica surfaces, with a small contribution from straining by size exclusion.
In-Well Optical Sensing—State-of-the-Art Applications and Future Direction for Increasing Value in Production-Optimization Systems
Authors: Drakeley B. K. , Johansen E. S. , Zisk E. J. , Bostick F. X. 
Published: December 2007

Abstract
For any production optimisation system to function effectively it must reliably receive quality data on demand. Over the past decade the reservoir monitoring industry has been addressing the issue of reliability including implimentation of a step-change technology – Passive Optical Sensing Systems.
Since the first installation of an in-well optical pressure gauge over 10 years ago, the industry has built a substantial track record with over 85 installations of P&T gauges and hundreds of DTS installations – acceptance is growing!
Initially Optical Sensing systems were expensive, complicated to install, and could only support limited applications. Today, they are on a par with electronic gauges with respect to performance, cost and installation simplicity. The state- of-the-art in optical sensing technology includes Bragg-grating based Pressure and Temperature sensors, permanent Distributed Temperature Sensing (DTS), Single-and Multiphase Flowmeters, and Seismic sensors.
This paper describes the operation of each of the sensing systems mentioned above, the data/information provided, together with details of application case histories. These range from simple single-gauge installations to complex wells with integrated pressure sensing, flow measurements and remotely activated zonal flow control – true Smart or Intelligent Wells.
The future direction includes even more complex intelligent completions and subsea deployments. Also high accuracy distributed array temperature sensing, optical distributed pressure sensing, sand detection, and distributed strain (e.g. for riser monitoring), are just a few of the new generation of sensing systems that are described in the paper.
As subsea continues to play an important role in our industry, the presentation (not included in this paper) will also include a synopsis from the SPE ATW "In-well Optical Sensing – Subsea Well Applications – Are We Ready?" held February 7th and 8th, 2006 in Galveston.
Enhancing Oil Production From Mature Fields by Focusing on Well-Intervention Management: North Oman
Authors: Al-Bimani A. , Al-Sharji H. , Aihevba C. O. , Fadhil A. , Al-Touqi M. , Al-Salmi M. 
Published: December 2007

Abstract
North Oman comprises four mature assets, producing 90% of its oil from old wells. In the drive to enhance oil production of the existing well stock, while arresting the natural decline of oil rate through better Well and Reservoir Management (WRM), well intervention work has increased in importance in the Company’s portfolio of activities. From 2003 a robust subsurface Well Intervention program is rigorously generated and vigilantly implemented and closely tracked. In 2005, some 3,600 well work activities were executed in the areas of Well Surveillance (well and reservoir data gathering); Well Optimization (oil generating activities, i.e. additional perforations, water & gas shut-off, stimulations, etc); Well Restoration (to maintain the old wells’ oil potential by ESP replacements, tubing wash, re-dress Gas-lift valve, etc) and Well Integrity (production casing repairs, fishing operations, annulus pressure testing) activities. Implementation of this program calls for utilization of various types of intervention technologies such as work-over hoists, electric / normal coiled-tubing units, electric wireline units, slick-line units and non corrosive pumping units. The oil generating (optimization) activities delivered some 5.4%, while restoration and integrity repair activities safeguarded some 23%, of the total oil production from North Oman, there by arresting the natural oil rate decline during 2005, at a low unit technical cost per barrel. As the fields get older, the well intervention work is expected to grow in term of magnitude, complexities, need for new technologies, cost impact and new challenges. Hence, the directorate has foreseen a need for continued concentration on improving the management of the well intervention to maximize the value realized in terms of oil reward and arrest of the natural decline oil rate.
This paper describes recent improvements to the Well Intervention Management Process in the North oil fields; from ranking of the activities, resource planning and optimization; activities planning and scheduling; execution of the plan, tracking of the operational / reservoir performance and feed back of learning for further improvement. These improvements are described by real examples of well interventions and the results achieved from managing the overall well intervention operations. It will also discuss the current operational challenges and limitations, and new technologies needed to address the issues.