bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Approach for Characterizing Your Portfolio
Authors: Pinkney Joanne 
Published: December 2007

AbstractUsing portfolio management and optimization techniques to allocate capital and select the best investment opportunities has been the subject of much discussion in recent papers and articles. However, there are still many practical problems associated with successful portfolio management within an organization. One of the biggest challenges is balancing the trade-off between modeling strategic-level issues versus capital allocation at the sub-strategic level. Two approaches are common. One is to take a high-level view and capture your portfolio at the business unit level. This approach enables clear strategic insights but is limited if business units are composed of several different types of assets contributing variously to the portfolio. A second approach is to start from the bottom up, with each project and sub-project captured in detail. This, however, is time-consuming and can produce confusing results, which are difficult to translate to meaningful capital allocation decisions.This paper describes a third approach: projects were captured at a detail level appropriate to 1) the goals of the organization, 2) project size relative to the portfolio, 3) project range of uncertainty, and 4) the decision-making level for capital allocation. Also, similar projects were grouped together and a "typical" project chosen to represent the group – using surrogates to reflect the group population. The paper discusses the importance of developing an understanding of key portfolio drivers and adequately characterizing the range of diverse investment opportunities before proceeding with data gathering. This has enabled much greater clarity in answering the often-asked question "Did the portfolio like ‘it’?", and has also established thresholds for material portfolio impact for different sizes and types of projects.A further benefit is identifying the critical economic and financial metrics that drive the company portfolio and feeding these back to the project originators so that they can focus on improving the accuracy of those metrics in the project economics.
An Experimental Investigation of Infiltrating an Immiscible Organic Spill in a Variably Saturated Soil
Authors: Mohammadi Kourosh , Mousavizadeh Mohammad H. , Kahawita Rene 
Published: December 2007

Abstract
The physical processes governing the infiltration and flow of an immiscible organic liquid in a variably saturated porous medium has been investigated with a laboratory experiment. In order to understand the risks posed by landfills or by oil spills; it needs to understand the mechanisms of migration of these contaminants and consequently the soil contamination. The experimental investigation contained two main sets of laboratory tests, some independent tests in order to find the physical characteristics of the soil such as saturated hydraulic conductivity, soil-moisture retention curves, and the dry density; and the second part was the investigating the NAPL flow using n-heptane. The results of the experiment proved that the NAPL moving downward from a coarse-grained material would encounter a higher entry pressure when a finer-grained layer is contacted.
Near Wellbore Stimulation by Acoustic Waves
Authors: Wong Sau-Wai , van der Bas Fred , Groenenboom Jeroen , Zuiderwijk Pedro 
Published: December 2007

Abstract
Reduced well productivity or injectivity is often caused by near-wellbore formation damage due to the interaction of reservoir formation with drilling and completion fluids. The problem can be further compounded by production induced formation damage. A prime example is fines migration and fines plugging of rock pores or gravel packs.
High frequency sonic waves, especially ultrasonic waves have been used in many industrial applications to remove contaminants like dirt, oil, and grease from parts immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high frequency acoustic waves. Although the concept is old, successful large-scale application of acoustic well stimulation is not common.
Greater understanding of the technology's applicability and limitations are essential in order to design effective downhole acoustic tool and guide successful field implementation. To this end, we have embarked on a dedicated project to mature the technology, which includes dedicated experimentation and tool design. In this paper, we focus on some key experimental results and discuss potential applications in production engineering.
Comprehensive Fracture and Production Analysis Leads to Optimized Fracture Stimulation Strategy in a Laminated Gas/Condensate Reservoir in Oman
Authors: Shaoul Josef R. , de Pater C. J. , Al-Hashmi Mahmoud , Langedijk Robert A. 
Published: December 2007

Abstract
Hydraulic fracturing has been an integral part of the development of two gas/condensate fields in Oman. The producing reservoirs are quite thick (160–190 m) and highly laminated, so fracture height growth and vertical coverage are key issues. High production rates and condensate production also mean that non-Darcy flow in the fracture is important. There are significant variations in permeability and depletion (following several years of production) within the reservoir, which makes any analysis more complicated. There has been an evolution in the fracturing strategy in terms of the number of treatments pumped per well (going from 1 to 5 fractures), the size of proppant used (12/20, 16/30, 20/40) and the size of the pad volume (75 – 350 m3).
Questions existed about the performance of the fracture stimulation treatments, particularly about whether the effectiveness of the fracture stimulations was decreasing over time, as one performance indicator showed. In order to answer these questions, a study was performed to evaluate the individual fracture performance based on the post-frac production logging data (PLT) which gave a production rate for each fracture in the well.
Monitoring Fracturing Fluid Flowback and Optimizing Fracturing Fluid Cleanup Using Chemical Frac Tracers
Authors: Woodroof Robert A. , Asadi Mahmoud , Warren Mark N. 
Published: December 2007

Abstract
Proper fluid and proppant placement are crucial to successful propped fracture stimulation. Numerous completion diagnostic technologies are available to characterize the placement of the treatment. Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and anecdotally monitored in the field. A technique utilizing a family of unique, environmentally friendly, fracturing fluid compatible, chemical tracers has now been developed for quantifying segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. Case histories demonstrate that individual, chemically-differentiated and/or proppant-differentiated, fracturing treatment segments and/or individual fracturing treatment stages are often not being effectively recovered. It has also been demonstrated that the chemical make-up and/or the proppant scheduling of these individual fracturing fluid segments may not only be detrimentally affecting their incremental cleanup but ultimately the production contribution from the corresponding portions of the fractured reservoir. The validation of improvements in fracturing fluid cleanup and production enhancement resulting at least in part from changes in the chemistry of the fracturing fluids and/or changes in proppant scheduling are demonstrated using the tracer technology.
Polymer Fluid-Loss Agent Aids Well Cleanouts
Authors: Rosato M. J. , Supriyono A. 
Published: December 2007

Abstract
Low-permeability gas sands are often cased, perforated, and hydraulically fractured in stages. Commingled production is common, and coiled tubing (CT) has become the prevalent medium for communicating multiple productive intervals between fracture stages and for use as a remedial workover method.
High differential pressures in the wellbore complicate CT intervention considerably. Fluid and solid bridging agents are sometimes used to combat fluid losses and associated well control problems. Calcium carbonate may be the most common bridging agent because it is inexpensive and easy to mix; however, removing the damage caused by calcium carbonate slurries to the formation and proppant packs is difficult and costly. Rock salt is widely used because it causes less formation damage, but it is ineffective against fluid loss. Furthermore, to prevent dissolution of the pill, saturated brine must be used as a workover fluid, increasing costs and contributing to scaling problems.
A unique fluid-loss control agent has been gaining acceptance for temporarily isolating fractured sands. This double derivatized, crosslinkable, hydroxyethyl cellulose (DDHEC) polymer leaves less than 0.5% gel residue by weight, minimizing impact on production. It has demonstrated a regained permeability of 91 to 93% under laboratory conditions and can be completely removed by acid. The polymer has been used in conjunction with 1.25- and 1.75-in. CT with a high degree of success. It does not require expensive brines, is resistant to solvents, and can be used with foam.1,2
The polymer has been applied in eight coiled tubing operations in south Texas, none of which has negatively affected production. This paper provides case histories for several of these field applications.
Sand Management: A Review of Approaches and Concerns
Authors: Mathis Stephen P. 
Published: December 2007

Abstract
As operating conditions become more severe, and the costs associated with well failure escalate, the need for effective sand control increases. However, in a time of tightening economic constraints, the need to control costs also drives decision making. In this time of apparently conflicting concerns, the industry has responded with a move away from traditional Sand Control to what can be more properly termed Sand Management.
Several projects described in the literature are concerned with a particular aspect of Sand Management. Whether it is a description of predictive modeling, preventing sand production through rate control and/or selective perforating, improved sand control through advanced completion practices of frac-pack or horizontal well gravel packing, or the latest in expandable screen products, these studies have focused on one (or perhaps two) aspects of an overall Sand Management project.
To fully grasp the benefit of this new completion paradigm, we must stop looking at well design with a preconceived answer in mind. Rather, all aspects of Sand Management must be considered when making field development decisions. It is the goal of this paper to bring the best from previous studies together to provide a solid review of available Sand Management techniques. However, since all decisions have either positive or negative consequences, this paper also reviews the economic and operational concerns associated with these decisions. An understanding of how initial decisions may impact future options will assist in enhancing our ability to optimize completion type selection.
A Mechanistic Model for Horizontal Gravel Pack Displacement
Authors: Martins A. L. , de Magalhães J. V. M. , Calderon A. , Chagas C. M. 
Published: December 2007

Abstract
This article presents the detailed formulation for each of the three steps of a horizontal gravel pack displacement operation, including sand injection and alpha/beta waves propagation. The main core of the model, aiming the definition of alpha wave height, is based on a well known two layer model. Initially developed for hydrotransport applications, this kind of model has been adapted by several authors for drilled cuttings transport analysis. Besides, a comparison between theoretical predictions and pumping charts from a field operation performed in Campos Basin is presented.
The Impact of Hidden Emulsions on Oil Producing Wells - Stimulation Concept and Field Results
Authors: Espinoza R. , Kleinitz W. 
Published: December 2007

Abstract
Ninety-eight per cent of the total cumulative production from the Cabimas Field has originated from Miocene reservoirs. The difference in density between Miocene oil and water is very small. In addition, this crude oil has a tendency to wet the surfaces of the reservoir rock. Under these conditions, a water- in-oil emulsion, and thus higher viscosities are favoured; this in turn impairs the well production capacity. Three wells were selected (R-A1, R-A2, and R-A3) for the treatment of hidden emulsions with the use of a wetting agent in an organic solvent system.
Another factor that was thought to impair the well production capacity was plugging of the Miocene slotted-liner gravel-packed completions by organic solids which are present. For considering this problem separately, two further wells (R-B1 and R-B2) were treated only with an organic solvent system.
Treatment preparation and pump operation (between 250 and 400 bbl/well) for all five wells were completed in a single week. All of these field operations were simple and were carried out with no operational or safety problems.
Thus, the use of the wetting agent proved to be a successful method for breaking hidden emulsions. Two of the wells treated in this manner, R-A2 and R-A3, respond with an increase in the fluid production rate. An exception was well R- A1; this negative result was due to the existence of a thief zone that fails to receive enough treatment fluid. Wells treated with organic solvents only did not show any change in production rate.
Formation Damage due to Pore Collapse During Pressure Depletion
Authors: Soares A. C. , Altoé J. E. , Bedrikovetsky P. , Ferreira F. H. 
Published: December 2007

Abstract
Pressure depletion during oil production results in increase of overburden effective stress in a porous matrix. This stress in turn causes rock compaction with deformation and consequential permeability and porosity reduction. Production rate decline during oil production due to rock compressibility has been observed in several reservoirs.
The rate decline during pressure depletion is particularly significant for totally unconsolidated or slightly consolidated sandstones, which are typical for Campos Basin reservoirs (Brazil).
Compaction with porosity reduction can improve production by squeezing oil from rock into wellbore. However, compaction can also impair permeability and reduce production. Understanding the interplay of these effects is essential for optimising well placement, for predicting of production rates and for reservoir management.
The collective effects of compaction phenomena on oil production and reservoir behaviour can be understood by means of mathematical experiments using synthetic, laboratory and field data. Mathematical modelling can do reliable prediction of oil production.
A mathematical model for radial oil flow towards wells in a deformable porous media is derived, and the boundary problem for the quasi steady state depletion processes is formulated. The solution is expressed by explicit analytical formulae. The model was applied to the reservoir R (Basin C, Brazil) and results were compared with laboratory data.
Structured Approach To Matrix Stimulation Proves Successful In Oman
Authors: Stevenson Eddie , Avadhut Raiturkar , Al-Harthy Khalfan , Abdulkadir Ramzi , Buijse Marten 
Published: December 2007

Abstract
In early 2000 the success rate for matrix stimulations matched the industry average of around 30%. In mid-2000 an integrated approach was launched, covering all aspects of the stimulation process, and today the success rate for engineered stimulations stands at 85%. This successful approach has been maintained over the past two years and enables new technology to be effectively introduced into the process and opens up additional opportunities. Long term sustained gains have been achieved allowing stimulations to become an effective tool for reservoir management. Examples of successful applications are included below.
Viscoelastic Surfactant Based Self-Diverting Acid for Enhanced Stimulation in Carbonate Reservoirs
Authors: Taylor Deidre , Kumar P. Santhana , Fu Diankui , Jemmali Mohamed , Helou Husam , Chang Frank , Davies Steve , Al-Mutawa Majdi 
Published: December 2007

Abstract
An improved viscoelastic surfactant (VES) based self- diverting acid system has been developed for matrix treatment of carbonate formations. The self-diverting acid contains a novel viscoelastic surfactant that undergoes an increase in viscosity as the fluid penetrates carbonate formations. The decrease in acid concentration as the acid reacts with the carbonate rocks promotes the transformation of spherical micellar structure into a worm-like structure that imparts high viscosity to the fluid. The highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. The VES based self-diverting acid contains no solids, so there is no bridging when it is pumped through tubing. Rheological studies showed that the acid rapidly developed viscosity as the acid was spent with CaCO3, and the spent fluid was stable up to 300oF. Diversion tests using multiple-core flood equipment showed effective wormholing in both high permeability and low permeability cores. The effectiveness of the new system in diversion and stimulation was confirmed in more than 70 field applications, both through increased well production and/or injection and production logs.
Experimental Study of High-Temperature Foam for Acid Diversion
Authors: Kam S. I. , Frenier W. W. , Davies S. N. , Rossen W. R. 
Published: December 2007

Abstract
Foam treatments are used worldwide for acid diversion in matrix acid well stimulation. Many field treatments require foam effectiveness at elevated temperature in the presence of both acid and corrosion inhibitor.
This study examines four surfactant formulations at room temperature, 220° and 400°F, with and without acid and corrosion inhibitor. The surfactants included amphoteric as well as nonionic foaming agents. The acid formulation was a mixture of chelating agent and HCl, with pH about 4. Formulations were tested at all three temperatures for foaming with N2 gas (80% quality) at back-pressure of 600 psi in sandpacks and for bulk-foam stability in a pressure cell.
Foam was created in most cases at 75°F without acid or corrosion inhibitor. Creating foam with acid and corrosion inhibitor at 400°F was more difficult, requiring high injection rates and lower foam quality. Once formed, strong foam had higher mobility at elevated temperatures than at room temperature. Addition of corrosion inhibitor was more adverse to foaming than acid itself. At 400°F foam propagation was slower, and steady-state pressure gradient was lower, than at 75°F. The two steady-state strong-foam regimes reported elsewhere were present at 220ºF and in the presence of acid. Pressure gradient at 220°F was lower in both the high-quality and low-quality foam regimes.
The bulk-foam stability results agree qualitatively with the sandpack results, but quantitative relationships between the two tests are hard to draw. These results also suggest that these surfactants degrade over a period of hours at 400°F but not at 220º. Residence time in the heated sandpack therefore may have been too short to fully represent field application at 400°F.
These results are consistent with decreasing foam stability at higher temperature; adverse interactions between foaming surfactant and inhibitor; easier foam generation and propagation at higher velocity and lower foam quality; and greater difficulty in creating foam under conditions that reduce steady-state foam strength.
These results can aid design of high-temperature foam-acid diversion treatments.
Gas Assisted Acidizing of Carbonate Formations
Authors: Shukla S. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
Matrix acidizing is a commonly used well stimulation technique in which acid is injected into the formation in order to dissolve a portion of the rock and hence, recover or enhance the permeability in the near well-bore region. In carbonates, when acid is injected, selective dissolution of the rock takes place creating highly permeable flow channels, called wormholes. In general, for a matrix acidizing treatment in carbonates, the deeper the wormholes penetrate into the formation, the better the outcome, as characterized by a lower skin factor. Thus, the deeper the wormhole penetration achieved with a given volume of acid, the more efficient the treatment. In this paper, we present laboratory results that show that wormhole propagation is enhanced by injecting nitrogen gas ahead of the acid.
As wormholes are being created, not all of the acid reaches the wormhole tip. A significant part of the acid is lost as fluid loss to adjacent pores. If this fluid loss can be controlled, then more of the acid can reach the wormhole tip, and hence the penetration of wormholes can be more efficient. This paper investigates the effect of saturating the carbonate rock with gas (nitrogen) prior to the injection of acid in order to reduce the permeability to acid, and thus reduce the fluid loss from the main wormhole.
It was found that gas injection prior to acid injection does significantly reduce the volume of acid required to propagate wormholes through cores. This effect is observed both at room temperature and at higher temperatures. The presence of gas in the core reduced the acid volume needed for wormhole propagation through the core by a factor of up to 3. The paper presents an extensive set of experimental results for both gas- and liquid- saturated carbonate cores subsequently treated with strong HCl solutions. We show that the acid volumes are generally smaller for the nitrogen-saturated cores, and that the wormholes created are narrower and less branched than in the case of water saturated rocks. We also show that the presence of oil saturation at residual water saturation in the core has a similar beneficial effect on wormhole propagation to gas injection. On the other hand, oil present at its residual saturation had little effect on the acidizing process. All of these results confirm the strong influence that fluid loss from a propagating wormhole has on the efficiency of the acidizing process in carbonates.