bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Modeling as a Key to Waterflood Development of the Fahud Field Natih-E Reservoir
Authors: Nicholls C. A. , Boom W. , Geel J. , Al Khodori S. , Al Lawati M. 
Published: December 2007

Abstract
The Fahud field is the largest oil field in Oman. Since its discovery in 1964, this giant carbonate field has gone through a varied production history including an unsuccessful early period of water injection. Since 1984, the field has been produced under Gas-Oil Gravity Drainage (GOGD). The efficiency of GOGD is dependent on an extensive fracture system into which the matrix oil can slowly drain to be recovered from a fracture oil-rim. Since the early 1990's extensive horizontal drilling in the field has provided a wealth of data which is gradually revealing the characteristics of what is a highly heterogeneous fracture system. From the analysis of well performance, mud losses and borehole image data supported by structural geological data, several areas and units within the Natih reservoir are now recognised as sparsely fractured and hence are inefficiently drained under the current GOGD recovery mechanism. This paper describes the data used to construct a fracture model for one such layer, the Natih-E, in Fahud NW. The model has allowed the identification of the most prospective area and units for a matrix waterflood incorporating the results of two waterflood pilot cells. The optimum well pattern for a waterflood development within two of the Natih-E subunits is proposed based on simulation results. The development is expected to provide an increase in recovery from 17% under a GOGD scenario to 40% for the waterflood. This is a clear example of how two different recovery mechanisms, GOGD and waterflood, can be used concurrently in one field to optimise recovery.
Justifying a Full Field Rationalisation: Preparing the Yibal Field for the Next 30 Years
Authors: Eckford Paul 
Published: December 2007

Abstract
The strategic position of the mature Yibal field within Petroleum Development Oman (PDO) is to sustain the company production levels and growth aspirations with a high rate of low cost oil for a prolonged period. The plans discussed in this paper are focused on how Yibal can become a world class operation, covering the full range of HSE aspects whilst fulfilling this mission. Yibal production facilities will be expanded by 50,000 m3/d, and a number of facilities and flowline rationalisation options have been investigated. A capacity expansion and a progressive transformation from the four existing gathering stations to one single gathering and processing station at Yibal A has been selected as the best option, and will be implemented in the near future. A key aspect is the retiring of existing gas lift facilities in favour of ESPs. The combined expansion and rationalisation project will contribute significantly to Yibal's value, in addition to making a large step-change in environmental performance and allowing strategic opportunities for future growth in the area.
Deterministic Reservoir Simulation Approach for Targeting New Wells in a Reefal Mature Field
Authors: Nosseir Mohamed A. , Khairy Aly M. , Heikal Salah A. , Tantawy M. 
Published: December 2007

Abstract
The Ras Fanar Field is a Reefal Limestone of the Miocene age. It is characterized by high porosity and permeability with random local hetroginities.
The field undergoes a strong acquifer support with a developing secondary gas cap which together with the variations in field lithology results in a very un-uniform fluid movement. Water coning and gas channeling took place in different wells at different parts of the field which disturbed the field production, and created unequally depleted areas that can result in spots of bypassed oil.
A multidisciplinary study was therefore conducted to have a better field understanding, and simulate the fluid movement in the reservoir to optimize the drainage pattern, and maximize recovery.
The work initially required the preparation of a firm database for various fluids movement. A successive set of maps was then constructed that defined precisely each fluid movement. The water level map was built to trace the rise of the OWC at different parts of the field. It showed areas of severe water coning, and those of homogeneous water rise. Similarly a gas level map was constructed showing the extension of the developing secondary gas cap across the field. Using both water and gas level maps, together with the structure contour map, an integrated composite map was constructed. A thorough interpretation of this map, finally leads to the oil leg map.
The oil leg map simulated the current reservoir status. It clearly revealed areas of extensive depletion, and those of high oil potential that were candidates for new infill wells. The work has been confirmed by a reservoir simulation study conducted later, which gave similar potential areas. The work integrity was finally confirmed by drilling four infill wells in those areas that proved to be a complete success.
In summary the work was conducted in about three months time. It has been the result of a close co-operation of multidisciplines including (engineers, production geologists, geophysicists etc..) which resulted in an integrated plan for efficient field development.
Experimental Investigation of Some Properties of Emulsified Acid Systems for Stimulation of Carbonate Formations
Authors: Bazin B. , Abdulahad G. 
Published: December 2007

Abstract
Acidizing treatments in carbonate formations is of paramount importance to restore or to stimulate the near-wellbore area by creating wormholes. Emulsified acid was found to be especially effective when the injection rate is low. This paper discusses the properties of some emulsified acid formulations.
The systems used in the study are mixtures of acid, diesel oil, surfactant and possibly a cosurfactant. Model systems made of anionic and nonionic surfactants are compared to the properties of a commercial emulsified acid. Experimental results are focused on the effect of the acid to oil volume ratio, the acid concentration and the surfactant nature. Rheological properties and temperature stability of the emulsion systems are analysed. Results of coreflood tests in limestone samples are presented which compare the behaviour of emulsified acids to the behaviour of plain HCl acid.
It is shown that emulsified acids are effective stimulation fluids at low flow rates: their main advantage is a deep penetration in conditions where plain acid gives compact dissolution patterns. On the opposite, at high flowrates, plain HCl gives better results. These results are confirmed by CT scanner tomography analysis showing highly branched wormhole structures even at low flow rates.
Guidelines are deduced to improve acidizing treatments in low permeability carbonate reservoirs.
Produced Water Management - Reservoir and Facilities Engineering Aspects
Authors: Evans P. , Robinson K. 
Published: December 2007

Abstract
Produced water management via injection, to disposal zones or re-injected into the source oil zone (PWRI), is being increasingly regarded as the best practicable environmental option - far preferable to discharge to the sea or evaporation ponds in the desert.
However, underground injection is not without its dangers and reservoir fracture control is a vital issue for many projects. The planning for and control of injection, either above or below fracture pressure, requires good, project-specific data on water quality and rock properties as inputs to injection simulation programs. Even so, these programs are currently subject to intensive research, especially for soft sands, layered formations and horizontal wells.
Research is on-going too in the areas of damage mitigation and stimulation of PWRI wells, and well failures do occur. In consequence, it is necessary to adequately monitor both well performance and injection water quality, and have in place contingency plans in case of a failure of the injection system. On-line monitoring of water quality may help avoid well damage/failure, and may also enable the upstream separation processes to be operated at their highest efficiency.
Practical and Efficient Approach to Construct a Detailed Full Field Model for Giant Field
Authors: Al-Hasan A. H. , Al-Awami F. H. , MohammedAli M. 
Published: December 2007

Abstract
Managing giant fields to meet certain objectives requires building three-dimensional full field models. However, because of the current software and hardware constraints, modeling must be approached differently. This technical paper presents the methodology and plan to develop a detailed full field finely gridded model for such a giant field.
The simulation modeling plan consists of the following four phases:

Phase I
Construction of a Base Model and utilization of coarsely gridded models covering the entire reservoir and the aquifer. These coarse models are used for global history matching and modeling the aquifer size.

Phase II
Development of four Areas of Interest (AOI) models covering the four areas of the field (North, Saddle, Central and South).

Phase III
Incorporation of all the history matching changes from the AOI models into the Base model. This model can be launched on a Massively Parallel Processing (MPP) simulator.

Phase IV
Integration of the reservoir simulation model with a surface facility network.
Experiences in Permeability Calculations in the Obayied Field (Egypt) Using Magnetic Resonance Imaging
Authors: Oraby Moustafa , Habib El-Sayed , Negm Ehab 
Published: December 2007

Abstract
Permeability is a key factor in well completion in many reservoirs all over the world. The dependency of permeability on the accurate determination of reservoir total and effective porosity, irreducible and movable fluids and the correct correlation between the pore throat and the pore body made it a real challenge. The capability of the Nuclear Magnetic Resonance to provide effective and total porosity, capillary bound fluids and movable fluids provides means for better estimation of rock permeability.
Magnetic Resonance Imaging Log (MRIL) was run in two cored wells in Obaiyed field in Egypt to determine the variation in rock permeability to better design well completion program and select best perforation intervals.
Obaiyed field is a gas sandstone reservoir with low porosity ranging between 5 to 10 porosity units. Obtaining a reliable permeability in this reservoir faced two challenges; the first due to the reservoir heterogeneity while the second due to the drilling mud.
The reservoir rock is heterogeneous and varies from very fine, fine to coarse-grained sandstone. The coarse grained sands represent the high permeability zones, which are imbedded within the fine-grained sand. The key issue in this reservoir is to determine the locations of these high permeability zones within the fine-grained sand beds for well stimulation planning. The determination of the T2 cut-off for both the fine and the coarse grained sands, which vary with depth due to the reservoir heterogeneity, generated a great challenge in determining the formation permeability. A function depending on an average of the T2 distribution is developed to provide the segregation.
The wells in Obaiyed field are drilled with oil base mud with very long relaxation time T1 that even exceeds the gas relaxation time. This property of the oil base mud, if it is not taken into account in logging and interpretation, makes it difficult to obtain a reliable porosity since the NMR will under-polarize the invading OBM as well as the residual formation gas. The time domain analysis technique (TDA) was used to overcome this problem.
In this paper, our experiences in such complex situation is discussed, core analysis is provided, core to log calibration in two wells is presented and recommendations for future applications in Obayied and other similar fields are suggested.
Reservoir Flow Units: A Comparison Between Three Different Models in the Santa Barbara and Pirital Fields, North Monagas Area, Eastern Venezuela Basin
Authors: Porras J. C. , Barbato R. , Khazen L. 
Published: December 2007

Abstract
The North Monagas Area presents apparently homogeneous thick sand bodies in the producing section. These sands, some in the order of hundreds of feet, have been until recently considered as single flow units. However, different production scenarios have indicated the presence of distinct flow units with particular petrophysical characteristics within each sand. Several definitions and techniques have been applied to determine flow units. In this study, flow units are defined as sediment intervals that maintain a similar relation between their petrophysical properties such as porosity, permeability, water saturation, pore throat radius, and storage and flow capacity, and that differ from the petrophysical characteristics of the intervals immediately above and below. Three different methodologies were analyzed and compared with the purpose of determining their similarities and divergences. The first method is derived from the sedimentological description of cores, using grain size as the main factor. The second method applies empirical equations based on pore throat radius an its relation to flow capacity, and their use in the determination of petrofacies or rock types, whereas the third method is based on a systematic model which uses the concepts of mean hydraulic radius and flow zone indicators to determine hydraulic units. The definition of flow units allowed a better petrophysical characterization of the field and provided better judgement for the selection of production and injection intervals.
Production of Heavy Oil Via Core Flow
Authors: Bannwart A. C. , Vanegas Prada J. W. 
Published: December 2007

Abstract
This work proposes a new technology for heavy oil lift by using the core annular flow pattern (shortly "core flow"). This flow arrangement can be induced through the lateral injection of relatively small quantities of water, in order to get a lubricated oil core along the pipe. With this objective in mind, an experimental apparatus was built and tested at laboratory scale (1 in. vertical pipe) using a 17.6 Pa.s, 960 kg/m3 oil and water at room temperatures. The frictional pressure drop was reduced by 700 to 2000 times with respect to single phase oil flow and is of the same order as the flow of water alone at same total flow rate. The total pressure drop was reduced by 45 to 150 times with respect to single phase oil flow and the optimum water-oil input ratio was in the range 0.07 – 0.5, depending on the superficial velocity of the oil.
Evaluation of Production Methods in the Morichal Heavy oil Reservoirs
Authors: Boardman D. W. , Lopez S. , Pineda F. , Zerpa L. 
Published: December 2007

Abstract
A thermal numerical simulation model has been used to history match an area of the Morichal-01 reservoir where cold production from horizontal wells and a continuous steam injection pilot project have been undertaken, allowing the efficiency of these processes to be assessed. The production performance of 47 horizontal wells in the field has been analysed analytically, and also modelled in the simulation; the study defined average well performance and quantified the potential gain from improving the artificial lift. The high reservoir pressures mean that sufficient reservoir energy is available to make cold production from horizontal wells the preferable option.
Multi-lateral well productivities have been evaluated to show the potential cost savings from introducing this technology, if artificial lift efficiency can be improved.
Improved Swi Determination and Producibility Estimation Using NMR, Dielectric and Induction Array Systems in San Jorge Basin
Authors: Breda Eduardo , Minetto Carlos 
Published: December 2007

Abstract
The productivity in shaly-sands and sand-tuffaceous reservoirs are adversely affected by changes in permeability and porosity due to varying cementation material, authigenic clays and dual porosity system. When those reservoirs contain viscous oil in presence of strongly fresh water, high capillary forces, the Swi determination and Producibility estimation become more complex.
That is the case in San Jorge Basin where the oils are frequently biodegraded, the water has low salinity and mainly accumulated in fluvials or lacustrine sandstones. The problem is even more pressing when oil viscosity varies within a hydrocarbon column or from zone to zone when attempting to commingle multiple zones.
To reduce those petrophysical uncertainties a model combining the response of NMR, Dielectric and Induction Array tools with new algorithms for T2 Inversion and Film Model was used.
The NMR Swi was compared with core and from these data, a new permeability index was derived. The Dielectric and Induction Array systems control the invasion and the heavy oil presence, improving the accuracy of productivity predictions and increasing hydrocarbon production.
This paper presents the applied model and successful results obtained in San Jorge Basin where the enhanced characterization of the reservoirs allowed us to increase the oil production after hydraulic fractures from 5 to 20 times initial rate.
Oil Production and Learning
Authors: Vargas de Alamo N. , Brandt R. , Paz F. , Gullón R. , Garcia A. 
Published: December 2007

AbstractThe basis for the change in Petróleos de Venezuela (PDVSA) in its Business Production Unit, is a very simple one: to reach the target of production of fluids, shown in PDVSA's Business Plan. It is necessary to duplicate the productivity of the technical personnel in charge of executing the plan.The company executes an ambitious plan for developing and maintaining competencies, addressed at an approximate population of 2,500 professionals in the areas of petroleum engineering, and geosciences, defined as key positions in the core areas.In order to attain this level of technical excellence, a complete learning plan, based on the interaction of several mechanisms, has been formulated. These are Integrated Training Programs, at a Basic, Intermedate and Advanced Level, as well as Special Training Programs, such as the program for the Formation of Seismic Interpreter and Petrophycisists. At the same time, it has implemented an ambitious plan for Fellowships for post graduate studies and technical assignments, in companies and international institutions of well-known technical level. Other types of training are also explored, such as Virtual Learning Programs and Self-development and On-the-job training. There has been an important investment of capital in the physical infrastructure, where these practical training programs in Integral Reservoir Management are carried out. The most relevant results obtained since the Competence Development and Maintenance Management in the Production Business Unit of PDVSA was created after the organizational transformation undergone in January 1998, are presented at the end of this paper.This significant advance in learning strategies will provide PDVSA with cadres of highly qualified technical personnel able to perform at the levels of efficiency required in the present Business Plan.
Characterizing Permeability Distributions with Integral Autocorrelation Estimators
Authors: Savioli G. B. , Saccomano A. F. , Bidner M. S. 
Published: December 2007

Abstract
Permeability distributions of very heterogeneous reservoir rocks are analyzed by applying different autocorrelation estimators: the classical semivariance estimator (CSV) and two moving window semivariance estimators (MW1 and MW2), introduced by Li and Lake1 in 1994. The goal of this work is to compare the ability of Simulated Annealing (SA) to represent actual heterogeneity, when each one of the three estimators is introduced in the objective function. The objective function is minimized by the Metropolis algorithm. With that aim, the generated image of permeabilities is compared with core measurements. Although MW1 and MW2 are more robust and resistant than CSV, they only present minor advantages when introduced into SA to describe permeability distributions.
Effective Integration of the Core Analysis and Wireline Datasets-Using a New Core Analysis Data Suite and New Software
Authors: Theologou P. N. , East R. D. , Curtis A. A. , Boult P. J. , Drake A. M. 
Published: December 2007

Abstract
Core analysis information is considered one of the cornerstones of formation evaluation. However, there seems to be general consensus that more could be done with it, both in the scope of the petrophysical data obtained and how it is used. In recognition of this, a suite of methods have been developed that provide a ‘new’ extended core data set, and software has been designed expressly for the interpretation of core data.
Historically, there has been a gap in the services provided by core analysis laboratories. Routine core analysis (RCA) provides core plug measurements such as porosity, permeability, fluid saturations, grain density and whole core gamma at high sample frequency and low cost. However, this data has limited interpretative potential. On the other hand, special core analysis (SCAL) provides a range of information with high interpretative potential, but at a low sampling frequency, primarily due to the cost and extended time frames associated with gathering the data.
A new data set was designed to compliment the current (RCA) data set, significantly extending its interpretative potential. The additional measurements performed are total, effective and furnace porosity, capillary pressure versus water saturation curve, surface area, core plug spectral gamma and an extended sample description. This new information fills the gap that currently exists between RCA and SCAL data, by providing significant interpretative potential at a high sampling frequency and in a reasonable time frame.
The computation of core-based or core-enhanced petrophysical interpretations has also been hampered by the lack of software designed expressly for modeling core data. Most petrophysical packages are decidedly log-centric, which has limited the effective integration of core and log data. Much core data processing is performed using spreadsheets, with inherent data integration and transfer limitations. To redress the balance, a core interpretation module designed to handle both the new data suite and existing core data, has been developed within a main-stream log analysis software package.
Applications using the new data suite include calibration of petrophysical parameters, the estimation of Qv profile from surface area data, the independent assessment of water saturation through the reservoir, and the estimation of initial reservoir flow properties at production start-up. The final outcome is that core analysis becomes truly a parallel formation evaluation discipline. In order to illustrate the core-log integration capabilities of the package, case studies are presented.
Pressure Response of Layered Reservoirs with Crossflow in the Presence of Gravity Effects
Authors: Savioli G. B. , Bidner M. S. , Cocco M. J. , Jacovkis P. M. 
Published: December 2007

Abstract
This paper deals with the understanding of well-test response in flow through bounded, heterogeneous reservoirs, in the presence of gravity effects. To generate these insights, we solve the two dimensional flow of oil by finite differences. The resulting system of linear equations is solved by a method based on Taylor Series of Matrix Functions (TSMF). The numerical simulator is applied to study the flow in a two-layer system with crossflow. The effects of vertical permeability and gravity are studied and insights into how these effects would alter well-test interpretation presented.