bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analytical Calculation of Minimum Miscibility Pressure: Comprehensive Testing and Its Application in a Quantitative Analysis of the Effect of Numerical Dispersion for Different Miscibility Development Mechanisms
Authors: Wang Yun , Peck Douglas G. 
Published: December 2007

Abstract
The newly developed analytical approach for calculating Minimum Miscibility Pressure (MMP) is tested using a wide range of slim tube test data involving a number of real crude oil systems. This shows that the analytical method for calculating MMP is capable of determining MMPs that are consistent with slim tube experimental data. The results indicate that this approach not only allows for rapid, accurate and objective determination of MMP for any displacement process, but also makes it possible to determine the displacement mechanisms in a quantitative fashion.
The analytical method is then used to compare with coarse-grid one-dimensional compositional simulation results to investigate the effect of numerical dispersion on the determination of MMP through compositional simulation for different miscibility development mechanisms. Results show that a quantitative description of the miscibility development mechanism as a result of the analytical MMP calculation methodology is a useful indicator of the impact of numerical dispersion on recovery.
It is shown that although for real crude oil systems the displacement mechanism is predominantly the combined condensing/vaporizing gas drive, the effect of numerical dispersion is more pronounced in displacements whose mechanisms are closer to the pure vaporizing gas drive. It is therefore argued in this paper that for detailed compositional analysis of miscible or near miscible gas injection processes, more care must be taken to account for the effect of numerical dispersion if the miscibility development mechanism is close to pure vaporizing gas drive.
Efficient Estimation of the Effects of Wellbore Hydraulics and Reservoir Heterogeneity on the Productivity of Non-Conventional Wells
Authors: Wolfsteiner Christian , Durlofsky Louis J. , Aziz Khalid 
Published: December 2007

Abstract
An efficient semi-analytical solution method appropriate for the approximate modeling of the performance of non-conventional wells operating under primary production is described. The approach, referred to as the s-k* method, accounts approximately for the effects of reservoir heterogeneity and for pressure losses within the wellbore. The accuracy of the method is demonstrated through comparison to detailed finite difference results. Extensive calculations for the performance of non-conventional wells in multiple realizations of log-normally distributed permeability fields are then presented. The effect of wellbore hydraulics on well performance is assessed for several different well geometries and for varying degrees of reservoir heterogeneity. Comparisons between ensemble-averaged quantities (i.e., results averaged over many realizations) and results for a single "average" (homogeneous) reservoir representation are also made. As expected, these calculations differ in general, though for some quantities (e.g., productivity ratio) the homogeneous results give very accurate estimates. The overall approach provides an efficient means for estimating the combined effects of reservoir heterogeneity and wellbore pressure losses on the productivity of non-conventional wells.
Practical Application of Fractal Model to Analysis Interference Test in the Naturally Fracture Reservoir, Amoseas Indonesia Inc.
Authors: Kristanto D. , Abdassah D. , Siregar S. 
Published: December 2007

Abstract
The use of fractal model in Pressure Transient Test Analysis was introduced by Chang and Yortsos in 1990. Their concept was derived from the assumption of Warren and Root model where their reservoir contains two systems with contrast in porosity and pemeability properties, which are well-known as matrices and fracture network.
The fracture network is assumed to be connected and distributed as fractal object in a homogeneous medium (matrix) of Euclidean Geometry. Fluid flow from reservoir to well occurs only through the perfectly connected fracture network. Based on these assumptions, Chang and Yortsos developed the unsteady-state flow of slightly compressible fluid and proposed an extension of the diffusivity equation to model transient flow in fractured reservoirs, especially in single well testing.
The physical and mathematical model descriptions are developed from Chang and Yortsos model. By Type Curve Matching technique, we can analyze the interference test in reservoir considered as a complex naturally fractured reservoir such as the one operated by Amoseas Indonesia Inc. Besides transmissibility and storativity we can also obtain the fractal dimension which can be used to predict the complexity of the reservoir.
Structural Evaluation of Petroleum Sealing Capacity of Faults
Authors: Sorkhabi R. , Suzuki U. , Sato D. 
Published: December 2007

Abstract
Japan National Oil Corporation is conducting a five-year project on the Evaluation of Traps and Seals. As part of this Project we have designed a conceptual model for evaluating faults as petroleum conduits or barriers in sedimentary basins. This structural evaluation draws on several geological databases from the North Sea, UK, Niger Delta, Utah, Texas, Gulf of Mexico, Trinidad, Persian Gulf, and Indonesia. Our model integrates various parameters affecting the flow properties of faults into tectonic setting and fault style, fault geometry, fault damage zone, fault rock in contrast to host rock characteristics, and fault chronology and time-scale (geological, production and seismic time scales). We distinguish between "fault traps" (due to juxtaposition of shale against sandstone layers) and "sealing faults" (in which mechanical and chemical changes along the fault plane produces a barrier to petroleum flow. Allan-type juxtaposition diagrams (fault-plane section analysis) are useful tools to evaluate fault traps but not sealing faults. Major processes of sealing faults include fault compaction and cataclasis, cementation due to fluid channeling along the fault, and clay smearing. Data on fault rocks and their corresponding undeformed host rocks show that faulting processes can reduce the rock permeability by two orders of magnitude. Quantitative a approaches for assessment of clay-smearing include Clay Smear Potential (CSP), Shale Smear Factor (SSF), and Shale Gouge Ratio (SGR). All these parameters depend on the thickness of faulted shale layer and fault throw. The available data indicate that CSP of &gt;15, SSF of &lt;7, and SGR of &gt;18% are threshold values for fault sealing in normal faults. While across-fault direction may be a membrane seal for petroleum flow, the fault damage zone may actually increase the permeability for the flow along and in the vicinity of the fault if the open fractures are not healed by mineralization and collapse. Analysis of fracture density, aperture, orientation, and connectivity, as well as fault-zone diagenesis are therefore important in fault-sealing evaluation. Our conceptual model is helpful in exploration because faults commonly occur in sedimentary basins and such a model provides a tool to rank a population of fault-bound prospects based on their relative and probable fault sealing capacity.
Geological Modelling of a Heterogeneous Volcanic Reservoir by the Petrological Method
Authors: Kawamoto Tomohisa , Sato Kozo 
Published: December 2007

Abstract
In dealing with heterogeneous thick formations, objectivity of well-to-well correlation is often hard to maintain and this is the case for a volcanic formation, the Minami-Nagaoka gas field. To overcome this difficulty, the refractive index is utilized to identify the different types of plagioclase, with which the well-to-well correlation is established in an objective manner and the formation is divided into six volcanic bodies.
One of the identified bodies corresponds to the productive zone encountered in the southern region of the field. This volcanic body is glassy rhyolite and extensively distributed throughout the field, even toward the northern region, where the productivity is poor. To explain the regional difference in productivity, various types of alterations are examined, including devitrification, montmorillonitization, chloritization, illitization, and albit ization.
Identifying the primary volcanic bodies and examining the secondary alterations enables us to construct a geological model of the subject volcanic formation. Integrated geological interpretation yields a clear view of the formation and a reasonable explanation to the productivity aspects.
Use of a New Reservoir Model in Pressure Transient Analysis Reduced Uncertainties in Asset Appraisal
Authors: Guo Boyun , Toro Mario 
Published: December 2007

Abstract
Asset appraisal using pressure transient data relies on match between actual reservoir pressure response and analytical models. However, it has been found that existing analytical models are not adequate for complex reservoirs detected by modern pressure gauges. Therefore there exist high uncertainties in asset appraisal based on welltest analysis in these reservoirs. It is highly desirable to develop realistic mathematical models describing the behaviour of complex reservoirs for asset appraisal.
This paper demonstrates applications of a new mathematical mode to evaluations of two complex oil reservoirs. The flow regime in the first reservoir during test was identified by the new model as linearly supported radial flow (LSRF). The new model provided a significant improvement in matching pressure transient data and data interpretations. The interpretation results were verified using a numerical welltest simulator.
Integration of Subsurface Disciplines to Optimise the Development of the Mardie Greensand at Thevenard Island, Western Australia
Authors: Tippet P. J. , Beacher G. J. 
Published: December 2007

Abstract
The history of the development of the Mardie Greensand reservoir at Thevenard Island illustrates the successful integration of subsurface modelling disciplines to enable the development and optimisation of a previously discarded hydrocarbon bearing zone. This has added 20-30 MMstb of Proved Reserves to the Thevenard Island asset. In particular, the use of G2-GOCAD modelling to generate a geostatistically populated grid proved invaluable in incorporating the heterogeneity of the reservoir. Formation evaluation modelling work contributed to the understanding of the reservoir petrophysics and better hydrocarbon identification from logs. Seismic EDGE (Enhancement & Detection of Geological Events) processing allowed the stratigraphic boundaries of the reservoir to be more accurately defined. Other seismic analyses have suggested that a northern extension to the field exists. The Chevron proprietary reservoir simulator, CHEARS, was used to model the reservoir and has also provided evidence for a northern extension to the field. The model has also been used to assess the value of infill well locations, and most importantly, the potential value of secondary recovery mechanisms such as water or gas injection. Finally, horizontal drilling technology and innovative geosteering techniques have contributed to the successful drilling of a number of horizontal, sinusoidal producing oil wells. Recently, the Mardie Greensand reservoir at the nearby Cowle oilfield was exploited as a result of an integrated effort using the knowledge gained at Saladin.
Rigorous Inclusion of Faults and Fractures in 3-D Simulation
Authors: Phelps Robert E. , Pham Tony , Shahri Ali M. 
Published: December 2007

ABSTRACT
Integration of well test results, horizontal well information, bore hole imaging, see Figure 1, 3-D seismic, and coherency analyses has made possible the ability to locate and define vertical faults and fractures. Fracture orientation, Figure 2, based on image log data from several wells, can increase our understanding of how the direction of these fractures effects reservoir performance. Conductive faults and fractures that contribute to fluid flow, along with stratified high permeability regions, must be included in our mathematical models.
Capturing the correct physics of fluid movement improve these reservoir simulation models accuracy as predictive tools.
To illustrate this point a sector model of the Beta reservoir was constructed using several different LGR (Local Grid Refinement) regions each represented a vertical fault and fracture system. These vertical fault-fracture systems, as depicted in Figure 3, were combined with high permeability stratified layers to construct a reservoir simulation model. This model was used to study possible inclusion of vertical faults and fractures, and investigate their effect on reservoir performance.
Integrated Reservoir Geomechanics Techniques in the Burgos Basin México: An Improved Gas Reservoirs Management
Authors: Berumen Sergio , Cipolla Craig , Finkbeiner Thomas , Wolhart Steve , Rodríguez Fernando 
Published: December 2007

Abstract
An overall geomechanical model was developed in the Wilcox sands of the Arcabuz-Culebra field, a tight gas reservoir in the Burgos Basin, northern México. The application of multiple technologies were integrated to build a geomechanical model of the field, which was used as a primary tool to predict fracture direction and stress field distribution. Advanced fracture diagnostic technologies that measure the created fracture geometry were used to support the geomechanical modelling.
The technical approach combined geomechanical modelling, hydraulic fracture mapping, fracture and reservoir engineering studies to optimise fracture treatment designs and improve the planning of well location and spacing. This methodology can be very important to avoid drilling unnecesary wells or leaving gas in place.
By integrating geomechanics techniques through single well reservoir modelling it was observed that ineffective well positioning could inhibit production by as much as 0.5 BCF per well. Fracture engineering analysis identified significant potential cost savings by reducing fracture treatment size and changing proppant type. In addition potential production increase of 3 BCF per well may be possible with re-fracture treatments. This paper discusses these results, and presents a case history that details the application and integration of reservoir geomechanics technologies to improve the practices in the gas reservoir management.
Reservoir Management Strategies For Development of Gas Dissolved In Water (Brine) Reservoirs
Authors: Manrique J. F. , Kaneko T. 
Published: December 2007

Abstract
Reservoir dynamics and the unique physics of the production behavior for this type of reservoirs make it an interesting reservoir enhancement problem. The potential of different well completions can increase significantly the existed production levels and the economic objectives as compared to current completions practices, which makes this a unique production engineering challenge.
Gas dissolved in water (GDW) reservoirs, are a unique application of reservoir and production engineering. However, development and optimization of this type of reservoir can be easily implemented by application of current technology. A workflow process for reservoir management of this type of reservoirs is introduced. An integrated approach was taken to properly characterize a typical GDW multi-layered reservoir.
Past performance was used to quantify potential. A reservoir simulation approach was developed to match and validate reservoir performance and to forecast production from alternative completions. Although the suggested alternate completions are relatively common and easy to implement, their application to this type of reservoirs is unique and innovative.
Economic evaluation was performed to determine feasibility of the alternative completions. Montecarlo simulations were used to evaluate and quantify financial risk and applied engineering for development of field best practices. Findings and results are encouraging and suggested strategies that may result in increased production and sustained economic return.
Application of the Method of Experimental Design to Quantify Uncertainty in Production Profiles
Authors: Venkataraman R. 
Published: December 2007

Abstract
Quantification of uncertainty in reservoir performance is an important part of proper economic evaluation. The uncertainty in our understanding of a given reservoir's performance (e.g. reserves at the economic limit) arises from the uncertainty in the information we have about the variables that control reservoir performance (e.g. permeability, oil water contact, etc.). The problem is complex since the influence of the variables on the reservoir performance is often non-linear. Conventional techniques often ignore this.
This paper describes the application of the method of Experimental Design to this problem. It consists of the following five steps :- (i) Identify the ranges of the important variables that influence the recovery, (ii) Experimental Design to identify the values of the variables at which the recovery is forecast, (iii) "Conduct the experiments" - use reservoir simulation to identify the recovery for each of the experiments identified in step (ii), (iv) Analyse "the results of the experiments" and establish a generalised multivariate correlation of the recovery as a function of the variables, (v) Validate the correlation arrived at in step (iv), and (vi) Predict the distribution of the uncertainty in the recovery. Here the term ‘recovery’ is used in a generic sense; the technique can be employed to any parameter of interest e.g. gas flow rate after ten years of production. The paper discusses an example of the application of the Composite Design to a North Sea gas field.
This technique has potential value in providing input to evaluation of economic risks in a project in the appraisal and development stages.
Early Water Breakthrough – X-ray CT Visualizes How It Happens in Oil-Wet Cores
Authors: Oshita Toshiya , Okabe Hiroshi , Namba Takao 
Published: December 2007

Abstract
In-situ saturation monitoring during a coreflood with X-ray CT scanner confirmed that the waterflood performance of a mixed-wet core is totally different from that of a water-wet core. Namely, it was observed that the brine injected in the mixed-wet core preferentially invaded into the most porous lamina, causing early water breakthrough at an outlet end. This result gives a significant insight into understanding the mechanism of unexpected early water production that has frequently been reported from some giant carbonate reservoirs in the Middle East. Many efforts have been made to grasp how such phenomenon took place. One of the most widely accepted explanations at present ascribes it to reservoir heterogeneities such as the existence of super permeability streaks. A drawback of this super-k concept is, however, that neither cores nor conventional logs could detect their locations. Thus, based upon the experimental result above, this study aims at associating the localized wettability conditions of the core sample with the early water breakthrough. For this purpose, a numerical study was carried out, using 3-D images of the in-situ saturation distribution obtained from X-ray CT scanning. Then, the waterflood performance of the mixed-wet core was successfully reproduced in the computer model. It was concluded from this numerical study that in spite of the small variation in porosity and permeability, the local variation in wettability can occur within the Berea sandstone core after it has been in contact with crude oil. As a result, the brine is preferentially imbibed in and runs through the more water-wet laminae, causing the finger-shaped water encroachment and, finally, the early water breakthrough.
Tilted oil water contact in the Cretaceous Caballos Formation, Puerto Colon Field, Putumayo Basin, Colombia
Authors: Carlos Estrada , Cesar Mantilla 
Published: December 2007

Abstract
After three attempts in the last 6 years to fully characterize the reservoir in the Caballos Formation in the Puerto Colon Field, different approaches to explain the reservoir heterogeneity have been suggested, each of which involves a great deal of uncertainty. Of particular importance is the fact that the oil-water contact has been found at varying depths from well to well. This variation could not be satisfactorily explained structurally nor stratigraphically. Bouttete et al, 1993, on the basis of incomplete 2D seismic information integrated to an extensive set of geologic and engineering data stated that there are three different reservoirs in the Caballos Formation. In 1996, Calderon et al, using additional well and seismic data, concluded that there is a single tilted oil water contact in the Formation. There is strong evidence supporting each of these models but there are still some inconsistencies. Recently, Peña et al, performed a thorough structural, stratigraphic and petrophysical review. This latest approach considered improved data management procedures and geostatistical modelling in order to produce a better picture of the reservoir. A rigorous validation and integration process under a project database allowed the workteam to improve the understanding of the system under study. By combining geostatistical modeling with geologic expertise it was possible to reduce much of the uncertainty and choose the most probable static and dynamic models of the reservoir. It was found that there are not sufficient elements in the static and dynamic models to account for the existence of three different reservoirs. A tilted OWC was accepted as the best representation of the reservoir for the available information.
Rejuvenation of the Aging Fairley Baram Unitized Field
Authors: Yusoff Shahbehri , Salleh Alias , Kamari Yusoff Mohd 
Published: December 2007

Abstract
Fairley Baram Unitized Field straddles the border of Brunei and Sarawak, Malaysia and is among the identified marginal fields that contain far greater HIIP than previous estimation. Realizing the upside potential, both joint operators, Petronas Carigali Sdn. Bhd. (PCSB) and Brunei Shell Petroleum (BSP) formed a team to review and plan for the field further development and appraisal activities.
The development phase of the campaign proved greater oil columns in proven reservoirs and developed 5.2 MMstb of oil reserves. The appraisal phase proved that the incised valley is predominantly shale filled with sand body at the base. The shale interval provides a seal and separation for reservoirs abutting to it. Deeper sands underlying the developed reservoirs were also proven to be hydrocarbon bearing. A revised volumetric incorporating the new data from the campaign indicates that the HIIP is substantially bigger than the pre-review volumes.
The re-processed 2D seismic, petrophysical, production and well data were fully utilized in the study. The deliverables are re-interpreted structural maps, in addition to the newly formulated depositional concept and revised petrophysical input. The depositional model is interpreted as an incised valley with slumping due to the tectonic movement or fall in sea level.
This paper discussed how the integrated field review enabled the team to better understand the field performance and better managed the uncertainties. The integrated field review also demonstrated that it is possible to turn around a ‘brown’ field and improved the field production rate by identifying additional proved develop reserves and at the same time replenish reserves from the appraisal targets.