bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integration of Sonic-VSP-Seismic Data for Reservoir Elastic Properties Evaluation
Authors: Tikhonov A. A. , Dobrynin S. V. , Kerusov I. N. , Glebov A. F. , Petrov E. I. 
Published: December 2007

Abstract
Exploration and production geoscientists use a number of characteristics reflecting such properties of reservoirs under study as structure, lithology, porosity, permeability, etc. Reliability of estimating these parameters defines effectiveness of reservoir development actions. Measuring elastic properties of formation allows computation of a number of parameters characterising reservoir's lithological properties and filtration characteristics. The information about distribution of elastic properties allows estimation of reservoir structure and elaboration of the optimal strategy for reservoir development.
Certainty and reliability of the geoinformation may be dramatically increased using integration of methods, studying elastic properties of reservoir in different frequency bandwidths using seismic waves of different types – longitudinal, shear, converted.
From this point of view, the integration of fullwave sonic log, multiwave VSP and surface seismic data may provide the effective solution for the task of investigating reservoir elastic properties. Integration of information obtained using these methods allows building of a single model that includes features of different ranks.
Observations, which use elastic waves of different types, make it possible to additional calculate such integrated parameters as Poisson ratio and to increase certainty of estimation of such characteristics as lithology and porosity.
Seismoacoustic measurements data, supplemented by log interpretation results, core analysis, hydrodynamic study results, provide a means to dramatically increase quality and certainty of the study.
Further Investigation of Drainage Height Effect on Production Rate in Vapex
Authors: Yazdani A. J. , Maini B. B. 
Published: December 2007

Abstract
Efficient recovery of heavy oil and bitumen is still very challenging and remains a subject of ongoing researches all around the world. Thermal recovery methods are generally accepted as viable and several successful field projects based on CSS or steam flooding or SAGD have been reported. However, these processes are not universally applicable and there are many problematic heavy oil reservoirs that are not good candidates for thermal processes.
Solvent based non-thermal heavy oil recovery methods are relatively new and still under development. The central idea in such techniques is to rely on solvent dissolution for viscosity reduction instead of heating. The viscosity reduction effect of solvents is comparable to that of steam. Among the solvent based methods, Vapex appears to be the most promising. Vapex is the solvent analogue of the SAGD process and uses essentially the same well configuration. A solvent vapor is injected instead of steam and the viscosity reduction occurs due to the dissolution and diffusion of the solvent in the oil. In thin heavy oil and bitumen reservoirs, where the thermal processes are likely to fail due to excessive heat losses, Vapex can be more successful. Nonetheless, the economic viability of Vapex remains uncertain due to much lower oil production rates predicted by scale-up of observed laboratory model results using the transmissibility based scaling criteria developed by Butler1.
In our previously reported experimental work, it was shown that the currently used scaling methods under-predict the increase in oil production rate with increasing drainage height. A bigger height dependency of the oil rates than the square root functionality proposed by the Butler's model1 was found experimentally. This observation was based on physical models of four different sizes, the largest of which was only 60 cm tall.
In this paper, the results of a new set of Vapex experiments are presented. This set of experiments has been carried out in a newly designed very large physical model, which to the best of authors’ knowledge is the largest Vapex experimental model ever fabricated. The results are, interestingly, in very good agreement with the trend of the previous experiments with the smaller models. The previously proposed scale-up relationship2 adequately predict the results obtained with the new physical model. The new results have been used to improve the previously reported empirical scale up correlation for the Vapex process. Conducting the experiments with different sand packs also reconfirms square root functionality of the dead oil production rate to the permeability.
Dual Porosity Equations from Effective Medium Theory
Authors: Berg C. R. 
Published: December 2007

Abstract
Aguilera's1 dual porosity model for fractures and matrix porosity was developed because fractures tend to lower the porosity or cementation exponent (m) of rocks. An assumption in the derivation of the dual porosity model was that fracture systems are parallel with the current direction, i.e. that fracture m (mf) is equal to 1.0. A new equation derived from effective medium theory allows mf higher than 1.0. The new relationship agrees closely with two models by Aguilera which allow mf greater than 1.0. In addition to the dual porosity equation, a new relationship is derived for calculating mf based on fracture orientation relative to current flow.
In the past, dual porosity models for vuggy porosity have mainly used the physical model of resistors in series with the inherent assumption that the vugs were non-touching. A new equation to calculate the effect of vugs on m is derived from effective medium theory. At low total porosity, calculations are very similar to those of the series model, but at higher porosities the results differ, eliminating the need to distinguish between connecting and non-connecting vugs. In addition, vug m (mv) can be varied on the basis of the shape and orientation of the vugs. When mv is raised to high values, the results are equivalent to the dual porosity series vug model.
A triple-porosity method is developed that utilizes adjustable mf and mv from new dual porosity relationships. The model works by first calculating a new, composite m for the bulk porosity and vugs and then it uses that composite value along with mf to calculate a triple-porosity m. When mf is equal to 1.0, the results resemble those of the triple porosity model of Aguilera and Aguilera2, but with increasing values of mf, the effects of fractures on triple-porosity m is dampened.
The Hydrogen Economy: Economics of Hydrogen Production From Natural Gas
Authors: Seddon D. 
Published: December 2007

Abstract
Hydrogen is a principal fuel for high efficiency fuel cell vehicles which produce zero emissions. Hydrogen fuel cell vehicles can be fueled competitively with conventional fossil fuel vehicles if the hydrogen is produced in large central facilities with access to low price gas. For many economies the price of gas is dependent on the price of crude oil (US). In times of high oil price, the production cost of hydrogen should be broadly comparable to the price of petroleum fuels in these economies. In economies in which the price of gas to large industrial users is not strongly linked to the price of oil (e.g. Australia), hydrogen production could be competitive with oil priced at $50/bbl.
The imposition of carbon taxes would impact unfavorably on the production cost of hydrogen from gas and, all other things being equal would require the imposition of additional taxes on fossil fuels to make hydrogen an economic alternative.
Although improvements to the technology of production are being researched, breakthroughs will not make a major difference to the production costs. A great unknown is the cost of reticulation of hydrogen and the distribution pressure required. This cost may make or break the production of hydrogen from gas as a viable technology for transport fuel. Improvements to conventional fuel vehicles, particularly the introduction of hybrids could erode any competitive position of hydrogen fuel cell vehicles.
Analytical Modeling of Chemical Flooding: One-Dimensional Two-Phase Flow Accounting for Ion Exchange
Authors: Pires A. P. , Ribeiro P. M. , Bedrikovetsky P. G. 
Published: December 2007

Abstract
Among different Enhanced Oil Recovery (EOR) methods, the injection of chemical solutions plays an important role in mature fields additional recovery. Analytical models for 1-D displacement of oil by water with chemical compounds have been developed since the 1960's. The interfacial activity and mobility control of a chemical flooding process are affected by the concentrations of the ionic species that are present in the water. This problem involves complex physical-chemical processes of interphase mass transfer, phase transition and transport properties changes. The one-phase displacement solution has been already developed and it is a well-known problem. However, its application is limited to already water flooded reservoirs. In this paper the solution of the two-phase problem is presented. A flow potential associated with the conservation of water phase is introduced and used as a new independent variable instead of time. This technique permits splitting the system of equations into a thermodynamic system and one transport equation. It is possible to show from analytical modelling of multi-component polymer/surfactant flood that the concentration "part" of the solution is completely defined by adsorption isotherms (thermodynamic part, called auxiliary system) and does not depend on relative permeabilities and phase viscosities. The number of auxiliary equations is less than the number of equations in the compositional model by one. Once the multi-component adsorption problem is solved, the 2-phase flow behavior can be predicted. This work shows analytical solutions of 1-D oil displacement by water containing two adsorbing cations and one anion for different salt concentrations in injected and formation waters. Electroneutrality and Gapon equilibrium equation are considered. One of the most important applications of these solutions is design of chemical flooding regardless of the water saturation.
Characterization of Multilayer Reservoir Properties Using Production Logs
Authors: Poe B. D. , Atwood W. K. , Kohring J. , Brook K. 
Published: December 2007

Abstract
This paper presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliverability performance of multi-layer commingled systems using multirate production log measurements. Both linear and non-linear systems are addressed in this paper, providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow, respectively.
Extension of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and well completion properties such as effective permeability, radial flow steady state damage /stimulation skin effect, and non-Darcy flow coefficient. In the specific case where the deliverability performance of a vertically fractured well is considered, estimates of the effective fracture half-length and average fracture conductivity may be derived from the analysis. In cases where the multirate deliverability tests are performed under boundary dominated flow conditions, conventional deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis. Applications of the analyses reported in this paper demonstrate the use of the analyses to evaluate the inflow performance measurements of commingled multi-layer reservoirs obtained using multi-rate production logs.
Production Performance Design Criteria for Hydraulic Fractures
Authors: Poe B. D. , Marique J. F. 
Published: December 2007

Abstract
This paper presents the results of an investigation of the design and analysis of the boundary-dominated flow production performance of a vertically fractured well located in a closed rectangularly bounded reservoir. The solution for dimensionless productivity index of a finite-conductivity vertically fractured well in a closed rectangularly bounded reservoir and the corresponding pseudosteady state shape factor of this type of well and reservoir completion under boundary-dominated flow conditions has been developed and utilized in this study.
The mathematical model described in this paper has been used to develop predictive and analysis graphical design charts of the dimensionless productivity index and pseudosteady state shape factors for use in improved hydraulic fracture stimulation design and evaluation. Example applications of the dimensionless productivity index and pseudosteady state shape factor solutions developed in this work are provided for fracture stimulation design. A production optimization strategy is presented in this paper based on the dimensionless productivity index solution for a vertically fractured well under pseudosteady state flow conditions.
Underbalanced Drilling Experience in PDO
Authors: Al-Saadi Anwar , Al-Bahlani Salah , Al-Mahrooqi Salima , Al-Riyamy Moutaz , Carrera Mariano , Bowling John , Al-Balushi Ahmed 
Published: December 2007

Abstract
In July 2004 a Northern Oman Carbonate reservoir asset team embarked on an Underbalanced Drilling (UBD) campaign after a detailed feasibility study. The main objectives of the UBD campaign were to improve the Productivity Index (PI) and test the validity of real time reservoir characterizations (RTRC) in UBD operations.
To date 16 wells have been successfully drilled UBD resulting in almost double the PI and better initial well production with a decline trend better or comparable to the offset conventional wells in the area.
Real time reservoir characterizations (RTRC) helped identifing the features contributing to water production and enabled real time decision making to optimize well path and sometimes extension of the well length by correlating real time resistivity data with real time production. RTRC also enabled optimum completion selection to maximize production as well as ESP sizing and installation of proper water shut off mechanisms (the preferred water shut off method is expandable Open Hole Clad "OHC"). Reservoir and geological models were updated in accordance with this analysis.
Other benefits seen from the UBD campaign include eliminating the need for stimulation, TLC logging (i.e. MPLT, FMI, etc…) and curing losses while drilling the reservoir section along with technology maturation of improved Down Hole Isolation techniques and the running of the OHC in UB situation.
A key success factor was the assimilation of a multidisciplinary integrated team comprising of the asset team, well engineering, new technology, drilling and UBD contractors. They all contributed to the success of UBD campaign which resulted in new oil delivery ahead of time and within budget.
As a result of the high success of the UBD campaign in 2004/2005 the asset team decided to drill all its oil producers underbalanced.
However, the challenges that have arisen are mainly in the cost of UBD packages and services as well as improving the reliability of some of the well control tools such Down Hole Isolation Valves (DHIV) and the application of contingencies in case of their failure.
3D Field-Scale Automatic History Matching Using Adjoint Sensitivities and Generalized Travel-Time Inversion
Authors: Daoud A. M. , Vega L. 
Published: December 2007

Abstract
Conditioning geologic models to production data is generally done in a Bayesian framework. The commonly used Bayesian formulation and its implementation have difficulties in three major areas, particularly for large scale field applications. First, the CPU time increases quadratically with increasing model size, thus making it computationally expensive for field applications with large number of parameters; second, the sensitivity coefficients that define the relationship between reservoir properties and the production response typically depend on either the number of model parameters or the number of data points; and third, the calculation of the prior covariance matrix (or its inverse) can be time consuming and memory intensive.
We propose a fast and robust adaptation of the Bayesian formulation for inverse modeling that overcomes much of the current limitations and is well suited for large-scale field applications. Our approach is based on a generalized travel time inversion and utilizes the adjoint method for computing the sensitivity of the travel time with respect to reservoir parameters such as porosity and permeability. The sensitivity calculations depend on the number of wells integrated which can be orders of magnitude less than the number of data points or the model parameters. The adjoint sensitivities can be computed from the pressure and water saturation distribution that is readily available from the numerical simulator. For solving the inverse problem, we utilize an iterative minimization algorithm based on efficient singular value decomposition. Prior information is incorporated using an approximation of the square root of the inverse of the prior covariance calculated using a numerically-derived stencil applicable to a wide class of covariance models. Our proposed approach is computationally efficient and more importantly the CPU time scales linearly with respect to model size making it particularly well-suited for large-scale field applications.
We demonstrate the power and utility of our approach using synthetic and field examples. The synthetic examples show the robustness and efficiency of this algorithm. The field example is from the Goldsmith San Andres Unit (GSAU) in West Texas and includes multiple patterns consisting of 11 injectors and 31 producers. Using well log data and water-cut history from producing wells; we characterize the permeability distribution, thus demonstrating the feasibility of our approach for large-scale field applications.
Investigation into Strengthening Methods for Stabilizing Wellbores in Fractured Formations
Authors: Soroush H. , Sampaio J. H. B. 
Published: December 2007

AbstractOver the last decades, drilling through fractured and unstable formations has proven to be challenging, specially in terms of wellbore instability. Stability of boreholes in these scenarios requires a careful consideration of in-situ stresses, rock strength, pore pressure, wellbore fluid pressure and drilling fluid characteristics. This issue is more critical and complex in fractured rocks, because of the need to consider more parameters than in other kinds of rocks. In fractured formations, fractures play an important role and rock wedges movement controls the instability. Also, fractures fillings are of paramount importance. In spite of this fact, there are only a few studies on stability of fractured rocks and their strengthening methods.The present paper aims to provide insights into wellbore stabilization in fractured rocks. A broad literature review was conducted on existing formation strengthening methods and their effectiveness for fractured formations. The work concludes with some recommendations for these kinds of formations and proposed topics for additional research and development.
Designing Hydraulic Fractures in Russian Oil and Gas Fields to Accommodate Non-Darcy and Multiphase Flow-Theory and Field Examples
Authors: Dedurin Andrey V. , Majar Vadim A. , Voronkov Andrey A. , Zagurenko Alexey G. , Zakharov Alexander Y. , Palisch Terry , Vincent M. C. 
Published: December 2007

Abstract
Non-Darcy and multiphase flow effects in hydraulic fractures have been well documented during the last several years. The pressure losses due to these phenomena are widely accepted to be of great significance in most gas well completions in the United States and elsewhere. While the importance in gas wells is evident, the authors pose the question of whether non-Darcy and multiphase flow effects are of concern in typical oil wells in Russia.
For the analysis, the authors evaluate three primary categories of Russian production wells: gas wells, oil wells producing above the bubble point, and oil wells producing below the bubble point. For each category, the authors describe the significance of non-Darcy and multiphase flow effects using fracture flow theory as well as state-of-the-art fracture production models. This paper will illustrate that non-Darcy and multiphase flow effects can substantially decrease the production potential of gas wells, as well as many of the oil wells found in Russia that are producing below the bubble point.
Historically, Russian oil wells have been intentionally operated above the bubble point. However, more aggressive well designs have recently been shown to increase production by over three-fold. The authors explore the economics of producing these wells below the bubble point and show that for these more aggressive strategies, the effects of non-Darcy and multiphase flow can be significant and should be accommodated during fracture design.
The authors propose solutions for mitigating these effects through various modifications to the fracture design including the impact of proppant selection on performance. Several operators within Russia have already successfully accounted for these phenomena in their fracture designs, and new field examples are explored, analyzed and presented in the paper. Recent field results are presented for Gazpromneft's Achimovskoya formation BV8 in Tomsk region (Western Siberia) and BP-TNK's field near Buzuluk in the Orenburg region (Volga-Urals). The results found here are compared to published results from the Achimovskoya sandstone in the Kalchinskoye oilfield, the BP12 formation of the Vyngayakhinskoe field, the Priobskoye and Sugmutskoe oilfields, and Gazprom's Yamburskoe gas condensate development.
Integrated Flow Assurance Modeling of Angola Block 18 Western Area Development
Authors: Watson M. J. , Hawkes N. J. , Pickering P. F. , Elliott J. , Studd L. W. 
Published: December 2007

Abstract
As oilfield developments become more technically and economically challenging, Flow Assurance has become crucial to the feasibility of projects. Consequently, Flow Assurance issues, such as hydrates or wax deposition must now be considered early in concept selection. Modern numerical methods, coupled with the latest software engineering techniques, now allow the rigorous calculation of multiphase thermal-hydraulic behaviour in an integrated asset model (IAM) on timescales acceptable for concept selection. The paper describes the application of a new IAM tool to analyse options for the development of fields in the Western part of BP's Angolan deepwater Block 18. Novel aspects include the embedding of field scheduling rules such that the drilling schedules were predicted automatically from the model. In addition, different field architectures were considered, including tubing and pipeline sizes, looping of pipelines and subsea multiphase boosting, and the impact on production rates and drilling schedules was quantified. Furthermore, the option to tie back to the planned Greater Plutonio FPSO was also modelled with the forecast ullage profile being imposed on production from the new fields. All calculations were performed using rigorous multiphase thermal-hydraulic models allowing Flow Assurance constraints to be analysed simultaneously.