bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Acid-Fracturing in Adverse Conditions: Lessons Learnt and Integrated Evaluation in the Kharyaga Field
Authors: Poitrenaud H. , Ferrand P. , Pouget P. , Manière J. 
Published: December 2007

Abstract
The Kharyaga field is located in Timan-Petchora region of Northern Russia, 60 km North of the Arctic Polar Circle. The field is producing principally from a Devonian age carbonate reservoir, this limestone formation having an average porosity of 8 to 12% and permeabilities ranging from 1 to 200 mD. The wells are completed as cased-hole, with a 7inch liner through the reservoir section. The perforated intervals range from 30 to 80 m in length and the wells were traditionally matrix-acid stimulated following perforation. The wells produced initially unassisted then later on, a work-over campaign was launched in order to equip the well with electrical submersible pumps (ESP).
Work-over operations were taken as an opportunity to re-stimulate lower-performing wells of the field. Several options were considered for this purpose from mechanically-diverted acid squeeze to propped hydraulic-fracturing or acid-fracturing this later option being ultimately selected. However, the rather adverse conditions existing both downhole and at surface rendered such an operation quite challenging. In the first place, the tectonically active nature of this region (West of Ural) led to anticipate significantly high fracturing gradients and difficulties to initiate a fracturing regime. Secondly, the weather conditions, with surface temperatures ranging from +20°C in summer to -50°C in winter and logistical issues necessitated adjustments to the fracturing fluids and job design. Finally other factors such as a high tendency of the Khariaga crude to precipitate wax, the presence of H2S or the flow-back through the ESP called for additional precautions.
In this paper we will show that despite these rather adverse conditions successful acid-fracturing treatments can be implemented in this region; we will discuss some of the key parameters that helped base the choice of treatment type and we will describe the lessons learnt during such treatments.
In addition, as the data-set available for this acid-fracturing treatment is unusually comprehensive with image logs, production profiles, pre and post-frac thermal logs, bottom-hole gauges and extended post-frac decline, an integrated evaluation of the treatment will be proposed.
A New Experimental Technique for Studying Gas Mass Transfer in the Crude Oil by Analysis of the Measured Dynamic and Equilibrium Interfacial Tensions
Authors: Yang D. , Gu Y. 
Published: December 2007

Abstract
This paper presents a new experimental technique and its computational scheme for studying gas mass transfer in the crude oil at high pressures and elevated temperatures by analysis of the measured dynamic and equilibrium interfacial tensions. In the experiment, a see-through windowed high-pressure cell is prefilled with a test gas at a prespecified pressure and a constant temperature. Then, a crude oil sample is introduced by using a specially designed syringe delivery system to form a pendant oil drop inside the pressure cell. Due to the dissolution of the gas into the pendant oil drop, the dynamic interfacial tension between the test gas and the crude oil keeps reducing and eventually reaches its equilibrium value when the saturation state is achieved. The sequential digital images of the dynamic pendant oil drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the dynamic interfacial tensions at different times. Theoretically, a mathematical mass transfer model is formulated to describe the diffusion process of the gas in the pendant oil drop. This model is numerically solved by applying the semi-discrete Galerkin finite element method to obtain the transient gas concentration distribution inside the pendant oil drop. With a pre-determined calibration curve of the equilibrium interfacial tension versus the equilibrium gas concentration in the crude oil, the dynamic interfacial tension at any time is calculated. The mass transfer Biot number and the gas diffusion coefficient are thus determined by finding the best fit of the theoretically calculated dynamic interfacial tensions to the experimentally measured data. This newly developed experimental technique is applied to measure the mass transfer Biot number, the diffusion coefficient, and the interface mass transfer coefficient of CO2 in a reservoir oil sample at P=0.1~5.0 MPa and T =27°C.
The Use of Well Testing for Evaluation of Connected Reservoir Volume
Authors: Levitan M. M. , Ward M. J. , Boutaud de la Combe J. -L. , Wilson M. R. 
Published: December 2007

Abstract
In its search for new oil and gas reserves the oil industry moves to more and more remote areas of the world and to technically challenging areas of deep water. Development of hydrocarbon resources in these environments is extremely expensive. To be economically viable, the newly discovered fields must be developed and effectively exploited with very few wells. This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well. High costs prohibit extensive appraisal activity and drive development decisions based on very few wells. Whilst these limited penetrations are often logged extensively using modern formation evaluation tools, the acquired static data cannot confirm that the wells will drain sufficient reserves. Evaluation of reservoir connectivity over large distances from the well requires relatively long and expensive well tests.
In this paper we review a number of critical points associated with design and execution of such tests. The key here is to ensure that the data acquired during the test will contain sufficient information to draw conclusions about the reservoir connectivity and to estimate the reservoir volume that is in communication with the well. We discuss the well test sequences used for this purpose, the tools and operational aspects of well test execution, the data acquisition, the well test analysis techniques, the accuracy and the degree of uncertainty of test results. We illustrate this application of well testing for reservoir connectivity with several real test examples.
Efficiency of Conversion of Work of Drainage to Surface Energy for Sandstone and Carbonate
Authors: Seth S. , Morrow N. R. 
Published: December 2007

Abstract
The increase in surface energy resulting from drainage of a wetting phase from a porous medium is often equated to the work of displacement determined from the area under its capillary pressure curve. However, capillary pressure versus saturation relationships are not reversible and do not represent quasistatic displacement. The increase in surface energy is less than the work done because of inherent capillary instabilities that are the basic cause of capillary pressure hysteresis. Nevertheless, identification of the area under a capillary pressure curve with thermodynamic work of displacement can be justified by interpreting the curve as a series of alternating isons (reversible displacements) and rheons (spontaneous redistribution at constant saturation). The efficiency of conversion of work to surface energy, Ed, depends on the increase in surface area that accompanies drainage. Surface areas of non-wetting phase/solid and non-wetting phase/wetting phase have been determined through displacement of a colored low-viscosity liquid resin which can be solidified so that thin sections reveal the distribution of phases and surfaces within the pore space of the rock. Two dimensional images obtained from thin sections were analyzed using stereology to obtain estimates of saturations and interfacial areas in three dimensions. For drainage of Berea sandstone to 20% wetting phase saturation, Ed was 36% which was less than one half of the efficiency of 85% for the same range of change in saturation determined previously for random packings of equal spheres. Values of Ed for the tested carbonate were about one half of those for sandstone. The wide variation is explained in terms of a simple pore model that relates Ed to aspect ratio.
An Upscaling Procedure for Constructing Generalized Dual-Porosity/Dual-Permeability Models From Discrete Fracture Characterizations
Authors: Gong B. , Karimi-Fard M. , Durlofsky L. J. 
Published: December 2007

Abstract
The geological complexity of fractured reservoirs requires the use of simplified models for flow simulation. This is often addressed in practice by using flow modeling procedures based on the dual-porosity/dual-permeability concept. However, in most existing approaches, there is not a systematic and quantitative link between the underlying geological model (in this case a discrete fracture model) and the parameters appearing in the flow model.
In this work, a systematic upscaling procedure is presented to construct a generalized dual-porosity/dual-permeability model from detailed discrete fracture characterizations. The technique, referred to as a multiple subregion model, represents an extension of an earlier method that did not account for gravitational effects. The subregions (or subgrid) are constructed for each coarse block using the iso-pressure curves obtained from local pressure solutions of a discrete fracture model over the block. The subregions thus account for the fracture distribution and can represent accurately the matrix-matrix and matrix-fracture transfer. The matrix subregions are connected to matrix in vertically adjacent blocks (as in a dual-permeability model) to capture phase segregation due to gravity. Two-block problems are solved to provide fracture-fracture flow effects. All connections in the coarse scale model are characterized in terms of upscaled transmissibilities, and the resulting coarse model can be used with any connectivity-based reservoir simulator.
The method is applied to simulate 2D and 3D fracture models, with viscous, gravitational and capillary pressure effects, and is shown to provide results in close agreement with the underlying discrete fracture model. Speedups of about a factor of 80 are observed for a complex 3D example.
Minimum Miscibility Pressure Prediction Using Statistical Associating Fluid Theory: Two- and Three-Phase Systems
Authors: Zhao G. -B. , Adidharma H. , Towler B. , Radosz M. 
Published: December 2007

Abstract
Miscible gas flooding is a well-known methodology for enhanced oil recovery. One of the key parameters in the gas flooding is the minimum miscibility pressure (MMP), which is the lowest pressure required to achieve multiple contact miscibility between injected fluid and oil. Among approaches for MMP prediction, analytical method and multiple-mixing-cell model are the most appealing approaches because they are robust and explanatory for complex miscibility process mechanism. These two approaches are usually coupled with empirical equations of state (EOS). Our goal is to develop a multiple-mixing-cell approach coupled with Statistical Associating Fluid Theory (SAFT) for predicting MMP for two- and three-phase systems. The coupling of SAFT EOS to a multiple-mixing-cell approach enables us to study the effects of gases and chemical modifiers.
In this preliminary work, for two-phase systems, we demonstrate that our multiple-mixing-cell model gives the same results as analytical method. For a gas-oil system with nc components, gas injection process leads to nc+1 constant-composition zones and the compositional path of the process, i.e. path in the compositional space representing the total composition, is controlled by nc-1 key equilibrium tie lines, i.e., initial tie line, injection tie line, and nc-3 crossover tie lines. In addition, our approach clearly demonstrates that both gas-oil ratio and fluid mobility do not affect tie-line compositional paths, i.e. compositional paths that lie on the thermodynamic equilibrium tie-lines, but they do affect nc-2 non-tie-line compositional paths. Therefore, both gas-oil ratio and fluid mobility do not affect MMP. In the context of multiplemixing-cell model, this fact has never been explicitly clarified before. The coupling of SAFT EOS to our multiple-mixingcell is also discussed.
The Selection, Application, and Misapplication of Reservoir Analogs for the Estimation of Petroleum Reserves
Authors: Hodgin J. E. , Harrell D. R. 
Published: December 2007

Abstract
This paper contains materials and concepts from both an engineering and geoscience perspective relative to the reliance upon suitable analog reservoirs for some or all of the pertinent reservoir rock and fluid qualities in the estimating of reserves quantities and the classification of such estimates.
The information in the paper is expected to be useful to professional reservoir engineers and geologists in predicting reservoir performance for reserves estimation, reservoir management and other predictive needs. The ultimate choice of the use and application of data from analogous reservoirs is always based upon the judgment of the evaluator but guidelines presented in this paper will assist in providing criteria for the more consistent application of analogs.
All judgment decisions in reservoir evaluation are based upon the evaluator's collective experience in reservoir geology or engineering and are thus subjectively analog based. Little of our collective experience, however, has been gathered in any systematic way where all pertinent reservoir and fluid characteristics have been identified. The pertinent characteristics go far beyond the typical measurements of depth, pressure, temperature, porosity, permeability and oil gravity – as primary parameters – and arguably should include depositional environments, mineralization, trapping mechanism, drive mechanisms, structural stresses, wettability, pore throat sizes and other often unknown or ignored features or descriptive parameters. Equally important is the recognition of the frequent and continuing misunderstanding and erroneous application of analog data, some of which is described in this paper.
The topic is significant because of the continuously growing interest in reliable reserves estimates and economic forecasts by companies, investors, regulators, governments and the public at large and because there are no similar papers available through the SPE library or other readily accessible sources.
Automated Route Finding for Production Flowlines to Minimize Liquid Inventory and Pressure Loss
Authors: Xiao J. J. , Al-Muraikhi A. J. , Qahtani A. M. 
Published: December 2007

Abstract
Conventionally, there is insufficient linkage between the selection of a route for a long production flowline and its hydraulic behavior under multiphase flow. A simplified, yet typical process in selecting and designing a multiphase flowline is as follows. Based on survey data, pipeline engineers pick the route. The selected route is then passed onto production or facility engineers for steady-state and transient flow simulation studies. The results of these studies are subsequently used to design the receiving facilities such as slug catchers and separators. This practice has, in many cases, led to slugging issues at gas plants and premature well shutoff due to high flowline back pressures in hilly terrain oil production lines.
In this paper, we present an integrated methodology and a tool that allows the production flowline path to be determined automatically, and with flow hydraulic behavior considered. The method uses digitized surface elevation data. In the route selection process, any number of surface features of different cost factors can be included such as loose soil, rocky hills, wet land, roads, rivers, existing facilities, non-passable installations, etc. Moreover, hydraulic calculations and economic evaluation can be integrated into the path-finding process to give a best route. This path-finding tool allows engineers to quickly evaluate several options such as 1) the shortest flowline path, 2) the path that gives the minimum total net uphills, 3) the path that gives the minimum net uphills and downhills, 4) the path that gives the minimum liquid inventory, and 5) the path that balances the pipeline cost and pressure loss.
Well Integrity Operations at Prudhoe Bay, Alaska
Authors: Anders J. , Rossberg S. , Dube A. , Engel H. , Andrews D. 
Published: December 2007

Abstract
This paper discusses the well integrity management system used at the Prudhoe Bay field located in Alaska. The focus is on systems and processes implemented to manage the well operations and interventions phase of a well's life. Well integrity is a multi-faceted discipline, spanning a well's life from design to abandonment. The engineering aspects of well integrity have received increasing attention in recent years as public scrutiny and resultant regulatory requirements have evolved. The issue of sustained casing pressure (SCP) on the annulus of a well has also shaped current well integrity practices. There have been several recent Applied Technical Workshops focused on well integrity, demonstrating its increasing importance. However, there is notably little well integrity related literature in the SPE paper library (see references 1-4 for a listing of relevant papers).
The well integrity management system used at Prudhoe Bay has been evolving since field startup in 1977. Extensive experience has resulted in the design and management of systems to ensure safe operations, compliance with industry standards, regulatory agency requirements, internal company policies and incorporating "lessons learned" from local incidents. This paper focuses on the operational and well intervention phases of a wells life and discusses evolution of the well integrity management system. Current operating practices are reviewed using BP's "7 Elements of Well Integrity" categorization. Finally, the data management system used to monitor the well integrity system status is reviewed.
General Transfer Functions for Multiphase Flow
Authors: Lu H. , Di Donato G. , Blunt M. J. 
Published: December 2007

Abstract
We propose a physically-motivated formulation for the matrix-fracture transfer function in dual permeability and dual porosity reservoir simulation. The current Barenblatt-Kazemi1-3 approach uses a Darcy-like flux from matrix to fracture, assuming a quasi steady-state between the two domains. However, this does not correctly represent the average transfer rate in a dynamic displacement. Based on one-dimensional analytical analyses in the literature we find expressions for the transfer rate accounting for both displacement and fluid expansion. The resultant transfer function is a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term representing fluid expansion. The expression reduces to the Barenblatt form for single-phase flow at late times, but more accurately captures the pressure-dependence at early times. For displacement we consider both imbibition and gravity drainage processes.
The transfer function is validated through comparison with one-dimensional fine-grid simulations and compared with predictions using the traditional Kazemi et al.3 formulation. We show that our method captures the dynamics of expansion and displacement accurately, giving better predictions than current models, while being numerically more stable.
Selection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of Horizontal Drilling in the Reservoirs with Different Depositional Settings (by the Example of the Sporyshevskoye Oil Field)
Authors: Ryzhov Sergey , Malyshev Vladimir , Kruchkova Tatyana , Zubareva Anna , Vasiliev Andrey , Maslennikova Yulia , Selemenev Sergey , Kolesova Marina 
Published: December 2007

Abstract
The Sporyshevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled, practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a necessity to develop the oil-water zones and marginal areas, zones with poor reservoir properties and minor reservoirs in order to maintain the production rates.
Application of horizontal drilling allowed achievement of the above tasks. Horizontal completions resulted in not only enhancement of individual well production rates, but also significantly improved the oil recovery. This goal was achieved through optimization of the development system and improved development of oil-water zone reserves and the reserves contained in the zones with poor reservoir properties. The use of the horizontal completion allows development of the reserves, which would have never been possible to produce with vertical wells because of poor economics. Another crucial achievement resulting from horizontal completions was the more efficient use of existing wells. Poor vertical producers were sidetracked; the vertical wells released due to drilling of horizontal boreholes were recompleted; the number of shut-in wells reduced.
Integrated Optimization of Field Development, Planning, and Operation
Authors: Guyaguler B. , Ghorayeb K. 
Published: December 2007

Abstract
Field management (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans, surface facility design/de-bottlenecking, uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimization from a hydrocarbon field. This involves, among others, the usage of reservoir simulators, surface-network simulators, process-modeling simulators, and economics packages.
We present a comprehensive, portable, flexible, and extensible FM framework completely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the FM interface, which is discussed in this paper.
The FM framework capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. One real field case that requires advance/complicated development logic is also presented.
Laboratory and Field Trial Results of Condensate Banking Removal in Retrograde Gas Reservoirs: Case History
Authors: Garzon F. O. , Al-Anazi H. A. , Leal J. A. , Al-Faifi M. G. 
Published: December 2007

Abstract
Gas condensate reservoirs experience significant productivity losses as reservoir pressure goes below the dew point. This productivity loss is related to the liquid dropout in the vicinity of the wellbore and the subsequent decline in gas rate which is associated to the reduction in gas relative permeability. To overcome this problem, gas condensate wells are often fracture stimulated to reduce the drawdown and subsequent formation of the condensate bank around the vicinity of the well. In gas wells that have been fracture stimulated to enhance productivity and to delay the creation of a condensate bank around the wells, the likelihood of developing a condensate bank near the wellbore is high due to lack of pressure support and or lower bottom hole flowing pressure in the well. The necessary lab work was conducted to evaluate the possibility of using filtered diesel to remove condensate banking from gas wells. Extensive core flood tests have been performed on carbonate reservoir cores using diesel, and combination of diesel with surfactants and mutual solvents. Laboratory results clearly indicated that there is a productivity improvement when using filtered diesel in combination with mutual solvent. In addition to this, a field trial to evaluate the benefits of such stimulation treatment has been implemented on a gas well that showed conclusive evidence of condensate banking. Pre and post pressure buildup tests data has been collected to assist in the evaluation process. This paper describes in detail the laboratory work, treatment design, and the field trial results of using such technique to remove condensate banking from gas wells.