bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Collaborative Environments Influence Culture and Behaviour
Authors: Williams P. 
Published: December 2007

Abstract
All companies are trying to produce organisational cultures that support their performance goals and growth aspirations.
This paper looks at how the increased connectivity afforded by the creation and use of collaborative environments can influence corporate culture by examining its impact on group dynamics and individual behaviours.
As well as looking at this inter-relationship, it also provides some advice on how to create these environments, including how to engage and enrol staff, and manage the transformation.
Finally a section is devoted to describing a Social Network Analysis tool that can benchmark and monitor the impact and effectiveness of collaboration.
CO2 Injection in Croatia: Revised Expectations for Ivanic and Žutica Oil Fields
Authors: Šunjerga S. , Domitrovic D. , Tuschl M. 
Published: December 2007

Abstract
First predictions of incremental oil recovery by CO2 injection at Ivanić oil field in Croatia (dating from year 2003) were based on laboratory data and a 3D simulation model matched against waterflooding history only. Since then, a field pilot CO2 injection was performed at Ivanić and the field data were used for corrections and modifications to the simulation parameters. A revised model of Ivanić field was used to generate more conservative recovery predictions. The same approach was then utilised for the pattern simulation model ofthe nearby Žutica oil field, a part of the same EOR project.
Permeability Modeling in Porous Media: Setting Archie and Carman-Kozeny Right
Authors: Haro C. F. 
Published: December 2007

Abstract
Archie empirical law is the basis of quantitative Petrophysics. The physical significance of this law is not well understood. This issue involves substantial uncertainty in oil in place.
Similarly, Carman-Kozeny (C-K) relationship is source of several permeability models. C-K is derived from Poiseuille equation, applicable in laminar viscous flow in straight non-communicating uniform tubes. Neither Poiseuille nor C-K formulae consider convective/inertial accelerations caused by changes in either cross section or flow direction. Implications include sizeable limitations in permeability modeling.
In this paper, appropriate hydrodynamic and electrical models are created using fluid mechanics analytical methods. The models delineate the velocity and electrical potentials, streamlines and controls, represented by C-K and Archie equations. This approach theoretically verifies both relations and demonstrates that:
Fluid circulation and permeability are optimally modeled invoking superposition of viscous and inertial regimes in nozzles, throats, diffusers, pipe networks, and arrays of solid particles. These hydraulic components, once assembled, emulate porous media well. Changes in fluid and electric flow direction are characterized by the flow around a corner solution of Laplace differential equation. The solution precisely defines rock frame, conductive phase, and hydraulic tortuosities, enabling direct ties to pore geometry. This facilitates permeability calculations utilizing the "perfect permeability transform" procedure.
Several experiments/examples are discussed to show validity. Some conclusions and technical contributions/applications are:
Electric measurements can predict hydraulic and petrophysical rock properties. Cementation exponent can be continuously computed employing acoustic tools and rock physics principles. Saturation exponent can be geometrically related to wettability and saturation using pore-scale modeling. A quantitative rock catalog can be implemented applying practical rock type definitions. Supported by these concepts, synthetic production logs can be generated to anticipate well performance, and to effectively assist in history matching. Archie law ceases being merely empirical. We gain a thorough physical understanding of its power law (fractal?) behavior. Rock responses can now be clearly explained and evaluated.
History Matching With Production Uncertainty Eases Transition Into Prediction
Authors: Little A. J. , Jutila H. A. , Fincham A. 
Published: December 2007

Abstract
The process of history-matching past reservoir performance involves making reasonable adjustments to key properties in a base geological model, either by ‘trial-and-error’ or using some computer-assisted approach, until observed data are adequately reproduced. Traditionally wells are controlled as individual entities and offtake rates that correspond to their historical allocations are imposed. This approach inherently assumes that there is no uncertainty in allocated well rates, and whilst a good match may be obtained, there is no guarantee that the resultant model will be robust in prediction.
It is frequently the case that a hiatus occurs when moving from well-rate controlled history-match mode to Group rate and well pressure (i.e. THP) controlled prediction, caused by wells exhibiting too great a potential – well PI's are typically adjusted to ‘correct’ this problem. This correction step is (a) time consuming (b) downgrades confidence in the relevance of the ‘match’, (c) reduces the predictive capability of the model, especially with regard to infill or new well production forecasting and (d) is different for each history match.
In this paper, a methodology is presented and illustrated whereby both static (geological) and dynamic (production allocation) uncertainties are addressed simultaneously during a computer-assisted search for multiple history-matches, which honour observed production performance and move into prediction without ‘correction’. Use of a Bayesian response-surface tool assists both in obtaining multiple matches and may be used to calculate statistically valid confidence intervals around predicted performance.
Tightness Testing of Environmentally Friendly Thread Compounds
Authors: Hoenig S. , Oberndorfer M. 
Published: December 2007

Abstract
In its most simple case the tapered round thread of casing or tubing is sealed by a thread compound i.e. a special kind of grease containing solids. To date, dopes that contain lead and other heavy metals, so called API-modified thread compounds, have found widespread use. This is surprising since metal free or even biodegradable thread compounds are available. OMV decided to initiate a project evaluating environmentally friendly thread compounds.
To find out which of the non toxic products have a good sealing performance, laboratory tests were carried out. Due to the lack of a standardised sealing tightness test for thread compounds a new benchmark test method was developed.
In the past, there have been two approaches for testing the "tightness" of the various thread compounds: the simplified grooved plate tests and the full scale tests on high pressurized and mechanically loaded pipes. Unfortunately, the plate tests do not provide reliable results, and the full scale tests are very expensive.
For the test described in this paper threaded pipes in small standard dimensions were used; relatively low testing pressures and no mechanical load were applied. Two parameters were implemented in a new way: temperature load and test duration. Temperature load was applied for the whole duration of the tests. The usual test duration was approximately two weeks but during the development phase some tests were run for several months.
This new combination of test equipment allowed inexpensive testing of many different thread compounds simultaneously. Not only performance differences between thread compounds could be examined, but also other relevant parameters such as varying temperature, pressure, torque etc. could be easily recorded.
After this new method had been refined seven environmentally friendly thread compounds were selected for testing, two of them being universal compounds. For reference purposes API-modified thread compounds from two different manufacturers were tested. Enormous differences in the sealing abilities of the products were found.
Life cycle costs can actually be reduced through the use of an inexpensive and effective thread sealing compound. Savings are possible due to a reduction in the number of workovers, of expensive down time and lost production.
It was clearly shown that some of the environmentally friendly thread compounds perform better and are cheaper than the old fashioned toxic API-modified compounds.
Technical and Economic Evaluation of Undersaturated Coalbed Methane Reservoirs
Authors: Carlson F. M. 
Published: December 2007

AbstractUndersaturated coalbed methane (CBM) reservoirs will not produce commercial quantities of gas until the reservoir pressure drops below the critical desorption pressure (CDP) of the coal. Such undersaturated CBM reservoirs exist worldwide. Standard methods of technical evaluation involve coring and core analysis to determine gas content of the coal. Because these standard methods require coring and subsequent transport of the core to a laboratory for analysis, they are expensive. Added to the on-site expenses of core retrieval is the cost of deferred knowledge manifested in typically long laboratory desorption tests of the samples and the associated financial cost of obtaining the results in the laboratory. Furthermore, because of the nature of the coal, such analyses typically do not provide a measure of permeability, another essential variable needed in the economic assessment of a prospect. A new, patent-pending methodology allows more expedient, yet accurate, determination of CDP and gas content of the coal. This methodology is based on the concept that only the capture of a water sample, following some simple rules, and its subsequent analysis are all that is required to accurately estimate the CDP of the coal. Such formation-water analysis can be done on site through production testing; or, depending upon the situation, the water sample can be analyzed in a fluid properties laboratory. The specific property of interest is the bubblepoint pressure of the formation water, which is demonstrated here to be equivalent to the CDP of the coal. Experimental results for coals in Wyoming's Powder River Basin show that the method accurately predicts the pressure at which the reservoir will become capable of production of CBM. From the CDP thus determined and a measured isotherm (e.g., from a sample gathered from drill cuttings), or from an existing isotherm representative of the coal in a given area, one can accurately estimate the amount of gas contained in the coal. With this gas content and a measurement of permeability obtained from standard methods of well testing, an accurate and timely prediction of well performance can be achieved using generally accepted approaches such as CBM reservoir simulation or more simplified modeling approaches. This predicted performance can then be used to estimate the economics of the prospect.
Software-Assisted History Matching—A Case Study of a Very Constrained Problem With Extensive Pressure and Saturation Data
Authors: Ghedan S. G. , Gibson A. P. , Sener I. , Gunal O. E. , Diab A. , Schulze-Riegert R. W. 
Published: December 2007

AbstractThis paper presents a case study using a Multipurpose Environment for Parallel Optimization with application to assisted History Matching. Evolutionary Algorithms and deterministic optimization schemes are integrated into a workflow controlling a large number of parallel reservoir simulations.The practical applicability of a software assisted history matching process is illustrated on basis of a real case study. The history matching process is discussed for an inverted 5-spot water flood pattern that had been subject to an extensive program of reservoir pressure and water saturation monitoring. Results are analyzed and compared to traditional history matching to identify the potential added valued and increased efficiency.The quality of the manual history match was reproduced for pressure data and significantly improved for saturation data. The resulting model has proven to show better forward modeling characteristics defined by matching of some blind test data. Due to highly constraining boundary conditions defined by pressure and saturation data, it was not possible to generate multiple solutions to this specific problem. Within the given constraints, the model tuning parameters had to be close to the values of the reference case to be able to match such constraining pressure and saturation data.In conclusion, the software assisted history matching process was able to improve the quality of the match within less time and effort. A lesson learned process is discussed focusing on the engineer acquiring more information and improving the understanding on reservoir uncertainties and the reservoir model behavior.
A New Mechanistic Model for Two-Phase Flow Through Eccentric Horizontal Annulus
Authors: Omurlu C. , Ozbayoglu E. M. 
Published: December 2007

Abstract
Multiphase technology is improving everyday in order to provide solutions for even most difficult design problems in most aspects of engineering. In drilling engineering, two-phase flow occurs during underbalanced drilling operations, especially in multilateral and extended reach wells. It has been a challenge for years to identify the flow patterns and predict the frictional pressure losses through circular pipes. Even less is known for annular geometries. In this study, a mechanistic model is developed in order to determine the frictional pressure losses occurring during flow through horizontal eccentric annular conduit. The flow pattern maps and estimated frictional pressure losses using the model are compared with experimental data gathered at METU-PETECTFL multiphase flow loop. The results show that model can accurately predict the flow pattern and frictional pressure losses for eccentric annulus. It is also observed that, the flow pattern boundaries for annular geometries differ from those for pipes having same hydraulic diameter.
Reservoir Characterization and Data Integration of Complex Mauddud-Burgan Carbonate Reservoir
Authors: Al-Bazzaz W. H. , Gupta A. 
Published: December 2007

Abstract
Mauddud-Burgan is a complex carbonate formation that contains substantial amounts of proven crude oil and runs south-east in Kuwait. It is a thin carbonate reservoir when compared to other Burgan reservoirs, which make it a candidate for horizontal drilling. The Mauddud reservoir offers about 40 feet of net oil-pay. It shows high porosity, about 18%, and a low matrix permeability between 0.8–10 mD. Several horizontal wells have been drilled, yet development of the Mauddud-Burgan program was abandoned due to the complexity of this formation. In 1994, only one well was a success and other nine were failures. Due to the structural complexity, prospect was less favorable than anticipated. With the world's demand for oil and the price of oil increasing, Kuwait Oil Company (KOC) is expected to be motivated to develop this reservoir.
The failed development of the past Mauddud-Burgan program involved a lack of understanding of this formation's complexity. Limited reservoir information for Mauddud- Burgan brought further development and planning to a standstill. This study proposes a detailed characterization of this formation to expedite future reservoir planning and development.
The proposed analysis involves seven aspects of reservoir characterizations which include: geological, thin-section, XRD, SEM, core, well logging, and, well test analysis. Core samples and data for the proposed studies were supplied by KOC, in co-operation with the Kuwaiti ministry of oil.
This paper reports results of several aspects of characterization, including geological and petrophysical analyses. The principal objective of the study is to integrate results manifested from experimental measurements of core samples and all other sources in support of a future development programs.
Correcting Underestimation of Optimal Fracture Length by Modeling Proppant Conductivity Variations in Hydraulically Fractured Gas/Condensate Reservoirs
Authors: Akram A. H. , Samad A. 
Published: December 2007

Abstract
A study was carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells.
At the gas velocities normally encountered in hydraulic fracture proppant packs, non-Darcy pressure drops dominate, and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of: Gas velocity (hence: rate and flowing pressure)Ratio of free liquid rate to gas rateStress on the proppantType of proppant
Thus, apparent proppant permeability will vary with distance from the wellbore, increasing towards the tip of the fracture where liquid ratio and velocity are lower.
This variation of permeability was explicitly modeled in the proppant pack by dividing it into segments and calculating the permeability in each segment. As a result of this modeling, the impact of increased fracture length on productivity was found to be more significant than in simpler modeling where one permeability value is used for the entire proppant pack.
The variation of apparent proppant permeability along the length of the fracture and its impact on well productivity are discussed in this paper. A comparison of predicted well productivity is also made with the use of a constant permeability value for the proppant in numerical and analytic simulators. We will show that using a constant proppant permeability value results in an estimate of optimal fracture length that is too short.
A Gas/Condensate Reservoir Productivity Evaluation and Forecast Through Numerical Well Testing
Authors: Shi-Yi Z. , Marius N. 
Published: December 2007

Abstract
Well productivity impairment due to two-phase flow in the near well region is a major concern in gas condensate reservoirs. There usually exhibit complex flow behaviours due to the condensate banking around the well caused by the bottom-hole pressure drops below the dew point (for most gas-condensate reservoirs). This leads to a drop in gas relative permeability, a decrease in gas production and a significant economic condensate remains in the reservoir.
In this study, we use a methodology to evaluate the productivity of gas condensate wells. Starting from the analysis of six available well tests, we have identified one test that most suitable for the aim of this project. Then we have used a well-developed workflow in the Institute of Petroleum Engineering at Heriot- Watt University to carry out the study. The workflow is to first characterize the formation for reservoir heterogeneity, the fluid properties and well productivity to evaluate the well dynamic performance (transient pressure and inflow). The formation evaluation of the well is performed to determine key parameters of the reservoir. Then fluid PVT test results are studied in details for reservoir fluid property in contrast to the phase diagrams for the whole gas column. The nature of the test, i.e. a gas- condensate reservoir with respect to the testing depth, interval and pressure regimes (on the phase diagram) have been re-ensured.
A radial homogeneous model was built to tune the well test simulation local grid refinement cell sizes and time steps, and a 3D geological model was built using the latest techniques to honour the reservoir heterogeneity. The model was then up-scaled into a fully compositional flow model for well test simulation. Numerical well test has been conducted with the same testing schedule and parameters (rock and fluids) as the existing well test. Finally, sensitivity studies on key parameters have been performed through the numerical well test simulation leading to the construction of families of reservoir system type curves. By the matching of these type curves to the existing well test, a numerical model is derived by tuning and matching to the real testing data. The derived model then can be used for future productivity forecast, as well as for new testing design.
A well test interpretation completed in this way has greatly reduced the analysis uncertainty and enhanced the understanding of the testing and the reservoir providing much more value from a well test.
Development and Implementation of a Scale-Management Strategy for Oseberg Sør
Authors: Fleming N. , Ramstad K. , Eriksen S. H. , Moldrheim E. , Johansen T. R. 
Published: December 2007

Abstract
Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It comprises a sequence of fault bounded structural units of varying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir support is provided by combined injection of gas and Utsira aquifer water. The wells are a combination of platform and subsea and comprise extended reach horizontals with complex geometry and lesser numbers of vertical wells.
Detailed scale predictions have been performed in order to identify the scaling risk for each producer. From this it was identified that the major risk to well performance and integrity was CaCO3 precipitation in the upper tubing with potential failure of the downhole safety valve. The risk varied from negligible to severe and reflected the variable composition of the produced water and well operating conditions. The scale predictions provided the basis for a technical and economic evaluation to identify an appropriate scale management strategy for Oseberg Sør. For those wells completed with downhole chemical injection lines the option to use these for scale inhibition was considered cost effective. In other wells where this option was not available, scale inhibitor injection into the gas lift system or squeezing using a viscosified treatment was considered viable.
The paper will provide the technical and economic reasoning for the scale management strategy selected along with field case histories for each treatment type (our experience with treatment using chemical injection lines, injection of scale inhibitor into the gas lift system and squeezing).
Review of Underground Gas Storage in the Bedded Salt Deposit in China
Authors: Guangjie Y. , Shen R. , Tian Z. , Yuan J. , Wang Q. , Yang M. S. 
Published: December 2007

Abstract
In view of the increasing importance of natural gas for China, especially when the West to east gas pipeline project started, Petrochina launched a study on constructing underground gas storage in the bedded salt deposit in 2000. The study was completed in the summer of 2005 after five years of work by experts from more than 6 countries. It provides information on new and emerging technologies, the status of gas storage in the bedded salt deposit, gas supply and demand, the geological evaluation and demands of salt caverns, the problems of caverns leaching, the reconstruction and utilization of existing salt caverns, gas injection and debrining, and so on. This report outlines the major aspects covered by the study, demonstrating some new viewpoints of underground gas storage in the bedded salt deposit. And now, 15 new salt cavern wells are constructing and 6 existing salt caverns have reconstructed by using some technology of this study.