bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Parameterization and Optimization Methodology for Assisted History Matching: Application to a Libyan Field Case
Authors: Al-akhdar Salem , Ding Didier Yu. , Dambrine Marc , Jourdan Astrid 
Published: February 2012

AbstractAssisted history-matching is now widely used to constrain reservoir models. The objective of history match process is to improve the model in order to reproduce the production history while honoring the structural properties of the geological model. For that purpose, an objective function is defined in order to measure the mismatch between the simulation results and the production history. This objective function is usually minimized using a gradient-based optimization algorithm. However, history-matching of a large number of parameters in hydrocarbon reservoirs is a challenge because of several reasons: scarcity of available measurements relative to the number of unknowns, computational effort required for large reservoir and the need of insure that solutions are geologically realistic. All of these problems can be helped by using algorithms that rely on efficient and parsimonious descriptions (or parameterizations) of reservoir properties.In this work, a history matching methodology is presented. First, a sensitivity study is performed for identifying the most relevant inversion parameters affecting the history-matching. The gradual deformation method is applied for the parameterization. Then, a new optimization technique, based on data partition for the gradient calculations, is studied for regional and well level history matching. The objective function is first split into local components, and the principal parameters are reduced for each component. In this context, we can propose perturbation designs with a smaller number of perturbations for the gradient computation. The proposed new technique is successfully applied on a real case in Libya in an integrated workflow, which makes history-matching with a large number of parameters tractable.
Increasing the Efficiency with Wireline Formation Testers and Reducing the Fluid Uncertainties in Thin-Laminated Low Permeability Reservoirs with in the Western Desert, Egypt
Authors: Ardila Mario , Ahmed Ramy , Dumont Hadrien , Naguib Mohamed , Zabcik Jim 
Published: February 2012

Abstract
Many sedimentary features of hydrocarbons at Western Desert are characterized as multilayered, deltaic, thinly and tight laminated sandstones consisting of sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations among nearby wells proved to be inconclusive in identifying hydrocarbons reservoirs owing to their thin beds, high shale content, and variable formation water resistivity. Missing hydrocarbon-bearing formations translates into lost productivity, while perforating water zones can have detrimental effects on well performance.
Given these complexities, fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. The main challenges faced during wireline formation testing in the reservoirs studied have been a) laminated, low mobility and thin formations with varying water salinity, b) no representative fluid samples due to deep mud filtrate invasion, c) eventual formation damage while drilling
The pretest/sampling efficiency with wireline formation testers and by using single probes has been traditionally very low in thinly laminated reservoirs because of the high possibility of dry or tight tests with long pressure stabilization time and not sampling or high contaminated samples. To displace invade fluids in low permeability formations can be challenging, usually requiring a high drawdown to pump the move filtrate from formation. To improve the job efficiency, High Performance packers and pumps are essentially in such environment that reduce significantly the differential pressure while pumping and increase the envelop to test zones beyond capabilities with the single probes. The Interval Pressure Transient Tests (IPTT) technique has been recently launched to increase the success ratio of wireline formation testers in getting reliable pressures and fluid analysis, including real-time monitoring of each survey by reservoir engineers.
Novel Rheological Tool to Determine Lost Circulation Materials (LCM) Plugging Performance
Authors: Kulkarni Sandeep , Savari Sharath , Kumar Arunesh , Jamison Dale E. 
Published: February 2012

Abstract
Lost circulation (LC), complete loss of drilling fluids into subterranean formations through natural/induced fractures, is a recurring problem costing the industry millions of dollars annually. Numerous solutions and drilling practices are applied in the field to mitigate, prevent or cure LC. Among these, the application of lost circulation materials (LCM) in the drilling fluids for plugging flow paths has been a widely accepted practice. LCM like ground marble, graphitic carbon and fibers are well-known to the industry. Different outcomes have been reported in laboratory tests and field applications when LCM is used in aqueous drilling fluids (AF) as opposed to non-aqueous drilling fluids (NAF). The present work provides a novel rheological tool to distinguish plugging performance of fiber-laden LCM in AF and NAF.
The LCM plugging performance is determined by conducting tests on permeability plugging apparatus (PPA) using a tapered slot (TS) on combination of fibers and particulates like ground marble and resilient graphitic carbon. It was observed that several combinations of fibers and particulates formed a plug in TS with minimal fluid loss in aqueous drilling fluids; however, when tested in NAF, LC was difficult to control.
To investigate the above performance difference, tests were conducted with an Anton Paar rheometer. Rotational rheometry is performed to measure first normal stress difference (N1) at low and moderate shears. It is found that the fiber contribution towards N1 in aqueous fluids is remarkably different from that in NAF. Microscopically, this difference in N1 could be attributed to the distinct fiber properties and orientation in these two systems that explain their contrasting performance in PPA analysis. Thus, the rheological technique provides a tool to identify LC control ability of the fiber-laden LCM system and optimize the concentration of fibers and LCM during the planning phase of drilling fluids.
Broadband Seismic: The Ultimate Input for Quantitative Seismic Interpretation?
Authors: Reiser Cyrille , Anderson Euan , Balabekov Yermek 
Published: February 2012

Abstract
Ideally, geoscientists would like to have quantitative information about rock properties, along with information about fluid content of potential reservoirs relatively directly from the seismic as this information is available as oppose to the well data. Historically, seismic images have stopped short of delivering this, as the seismic bandwidth was limited due to the conventional streamer design and acquisition method.
The ability to predict reservoir properties away from the well using seismic information is a key element in quantitative interpretation. Quantitative seismic interpretation combines various types of data: well, seismic and seismic interpretation or geological prior information. Thus, this workflow is integrated and the quality and accuracy of each individual constituent is of great importance to the accurately estimate the volume of hydrocarbon in place in a particular reservoir interval.
Seismic plays a key role in this, and if the seismic data contains very strong low frequency information and the seismic image is of high quality/resolution, it is possible to directly estimate the absolute impedance at each point within a seismic volume.
Over the last few years, new acquisition methods and technologies exist aiming to provide a broader seismic bandwidth: streamer towed shallow at the front and going deeper at the mid of the streamer, towed acquisition with some streamers at shallow and deeper depth, and the dual-sensor towed streamer.
These new broadband seismic data volumes are bringing the seismic a step closer to the reservoir and this is what we will try to demonstrate in this presentation. We will have the latest look at some of the newest and most exciting improvements in reliably unraveling the rock properties from the 3D seismic data.
Multiple EOS Fluid Characterization for Modeling Gas Condensate Reservoir with Different Hydrodynamic System: A Case Study of Senoro Field
Authors: Suwono Sugiyanto Bin , Hendraningrat Luky , Febrianto Dwi Hudya , Nugroho Bagus , Marhaendrajana Taufan 
Published: February 2012

AbstractA proper analysis and fluid characterization is an essential key for successful modeling the behaviour of gas condensate reservoir. This paper demonstrates a robust multiple equation of state (EOS) modeling process for gas condensate reservoir at Senoro field. Senoro is a new major gas condensate field in East Indonesia with estimated IGIP greater than 2 Tcf and CGR range from 3-80 STB/MMscf. Senoro field is divided into two structures: the northern part is a carbonate reefal build-up, namely Mentawa, member of Minahaki formation, and the southern part is a platform carbonate Minahaki formation. The hydrodynamic condition in both formations poses a challenge to fluid characterization, where Mentawa member has both oil and gas with active aquifer, while Minahaki formation only has gas bearing rock with aquifer.Senoro field has collected 36 samples, measured from down-hole and surface. The samples also cover composition analysis for surface recombined fluid. The required laboratory experiment such as CCE, DL and CVD have also been measured. The mathematical recombination was performed as a quality check to measure well-stream composition.Two EOS models have been developed successfully to determine physical properties and to predict the fluid behaviour of Senoro. The heptanes-plus fraction is split into three pseudo-components to characterize fluid using Gamma distribution model. The fine-tuned fluid properties from all available data match both EOS models satisfactorily. These EOS models have also been matched with historical single radial welltest model. Compositional grading has also been developed to generate compositional map.These established EOS models are used for compositional simulation. The gas and condensate profiles now could be predicted for optimizing field development plan. The use of EOS models can lead not only to a further field development strategy, but also to optimize the surface processing facilities.
Assessment of Unconventional Shale Reservoir: The Fegaguira Fm, Chotts Basin, Tunisia
Authors: Rezouga Nawel , Mohamed Anis Belhaj , Saidi Moncef , Bouazizi Ibrahim 
Published: February 2012

Abstract
Geochemical data indicate that the Late Silurian-Early Devonian Fegaguira Formation is the main source rock that has been charged the Ordovician and the Triassic reservoirs in the Chotts basin, South of Tunisia. Its good to excellent geochemical characteristic and its convenient maturity range allow it to be nominated as a good shale reservoir.
The reservoir assessment was based essentially on geochemical and mineralogical elements including: (1) source-rock distribution, thickness, organic richness, maturity level, petroleum generation and migration; (2) organic facies distribution, quality and kerogen transformation; and (3) mineralogical assessment, clay type and quartz richness.
A geochemical database consisting of 224 cuttings samples of the Fegaguira Formation was used to determine its geochemical characteristics including mineralogy. The examined shales show different thickness distribution that decreases towards the south east. They were subdivided into three distinct units according to their diagraphic responses, lithology and organic richness. The two upper units exhibit good total organic carbon averaging 5%, an original hydrogen index averaging 560 mg HC/g of TOC suggesting that the Fegaguira Formation was originally rich in type II organic matter (oil and gas prone kerogen), maturity ranges from 0.7 to 1.1 % R0, transformation ratio is about 0.78% and quartz richness up to 16%.
Detailed framework studies in petroleum geochemistry, lithostratigraphy and mineralogy combined with conventional modeling were used to estimate the unconventional oil and gas resources of the Fegaguira Formation.
The important organic content, the carbon transformation ratio, the gas derived both from kerogen cracking and oil-to-gas cracking, including the calculated porosity and the quartz percentage suggest that the Feguiguira Formation is a promising reservoir.
Geochemical Correlation and Migration Studies of the South Eastern Part of Tunisia
Authors: Rezouga Nawel , Mohamed Anis Belhaj , Saidi Moncef , Bouazizi Ibrahim 
Published: February 2012

Abstract
Several wells have been drilled in the south eastern side of Tunisia but only two wells are producing. However, to better understand the petroleum system mechanism of the area, a geochemical study was performed including oil-oil and oil-source rock correlation that was proved to be an essential tool for assessing oils occurrence, source rocks characteristics, their depositional environments and their distributions. The geochemical study was followed by 1D basin modeling to better understand the petroleum system functioning of the area.
The geochemical survey is based on the analysis of a total of 214 cutting samples and 6 crude oil samples. In a first part, potential Silurian and Ordovician source rocks were analyzed by Rock Eval to characterize their petroleum potential. In the second part, DST oil samples are correlated to Silurian and Ordovician source rocks using biomarkers and light hydrocarbon fraction. Migration distances calculation was based on carbozoles and benzocarbozoles.
Rock Eval results show that Silurian Hot shales exhibit good petroleum potential with mature type II oil prone kerogen, while Ordovician Shales show poor to fair petroleum potential and contain bad preserved type II kerogen.
Geochemical correlations study proved that the Silurian Hot shales are the main source rock in the basin and excluded any contribution from the Ordovician shales.
Carbozoles and benzocarbozoles concentrations in the oils of the northern part of the area suggest close proximity to the source kitchen while oils from the southern part seem to be sourced by a kitchen located in Ghadames basin.
The 1D modeling indicates that oil and gas generation from the Silurian hot shales began in the Carboniferous at about 360 Ma and reaches the maximum generation phase in the Upper Jurassic at about 160 Ma. The Hercynian unconformity surface was the main drain of secondary migration in the basin.
Application of New Techniques for Characterization of an Eocene Carbonate Reservoir in the Gulf of Suez, Egypt
Authors: Van Steene Marie , Vallega Valentina , Shaaban Sahar , Ghadiry Sherif , Haddad Elie , Bassim Essam 
Published: February 2012

Abstract
A variety of recently developed techniques are available to improve carbonate rock characterization. This paper reviews the application of these techniques on an Eocene carbonate reservoir from the Gulf of Suez.
Spectroscopy data was a main driver of the formation evaluation. It allowed an accurate determination of clay, pyrite and siderite with a good match to core data, while the photoelectric factor could not be used because of high barite content in the mud. Magnesium from spectroscopy indicated small amounts of dolomite were present.
Since rock texture has a strong impact on porosity and permeability in carbonates, texture-sensitive tools must be included in the evaluation. Based on nuclear magnetic resonance (NMR) data, porosity partitioning analysis showed that the porosity is dominated by micro and meso pore sizes. While the default correlations used for NMR in carbonates considerably overestimate permeability, a modified SDR equation was applied to predict permeability more accurately, providing a good match to core data.
Hydrocarbon properties have been found to vary vertically. NMR fluid identification stations were used to characterize the variation, which was validated by the drillstem test (DST) results.
Tar was identified based on the comparison of total porosity and NMR porosity. This is an important parameter as tar can affect the reservoir producibility.
Fracture analysis was performed on a data set of microresistivity image and sonic Stoneley data. The analysis performed on the Oil-Base MicroImager (OBMI) identified the orientation of the fracture system. The Stoneley wave processing determined that the majority of the fractures encountered in the reservoir were healed. This conclusion was supported by the core analysis results.
The work presented in this paper demonstrates how integrating the measurements from various tools and sources provides a good understanding of reservoir producibility in carbonates. The integrated evaluation was validated with core and well test results.
New State-of-the-Art Asset-Optimization Data Applications for Intelligent Completions in Digital Oilfields
Authors: Allen Clifford , Smith Robert 
Published: February 2012

AbstractInformation provided using intelligent completions in digital oil fields is increasing in importance, as it has the capability of minimizing the needs for custom data-gathering solutions as well as simplifying industry-data interfacing standards for multiple devices and systems. For assets using intelligent completions, solutions offered are attained by a combination of subsurface and surface or subsea sensors provided by several vendors.Challenges arise when attempting to manage the interfaces required for providing real-time data from all points of interest (i.e., subsurface choke positions, flow, pressures and temperatures, wellhead positions, subsea facility readings, etc.).This paper describes the design and implementation of an integrated data-applications system that can integrate data from multiple workflow sources for the purpose of maximizing field performance. The asset optimization applications acquire operating parameters from all points of interest, making them available to software modules designed to estimate key well-performance indicators.The asset-optimization application discussed here is an integrated system that performs the following five services. A data-interfacing methodology acquires data from multiple sources or directly from down-hole devices. The integration service converts the subsurface and surface data to engineering units of measured well parameters. The well performance service uses well PVT and device-integration service values to execute complex calculations, like virtual flow metering, water-cut estimates, etc. The human/machine/interface service provides visualization, trending, and querying. The connectivity service facilitates structured data transfer to field historians.The paper will explain how the system works and its implementation into fields of different scales and types to reduce information technology (IT) customization, simplify interfacing of multiple devices or systems, and accommodate evolutions in IT. Additional system benefits that included more efficient management of real-time data security, quality, redundancy, and mirroring will also be provided.
Proper Selection of Upscaling Techniques for Different Production Processes
Authors: Shehata Ahmed M. , El-Banbi Ahmed H. , Sayyouh M. Helmy 
Published: February 2012

Abstract
One main challenge in reservoir modeling is the computational costs of flow simulation. Although computer power has significantly increased in the past few decades, effective upscaling to reduce computation time in heterogeneous reservoirs still remains a challenge.
This research demonstrates the results of a comprehensive study on common upscaling techniques for porosity and permeability. This work aims at providing guidelines on which upscaling methods are superior for different depletion/production processes. The processes investigated include straight depletion, water injection, miscible and immiscible gas injection.
Several fine grid heterogeneous models were developed using actual field data and heterogeneity was evaluated using Lorenz and Dykstra Parsons Coefficients. Those different models were used to generate benchmark results for comparison with coarser models developed at different levels of coarsening and with different upscaling algorithms. Several scenarios were investigated in order to identify which upscaling algorithms result in the closest match with the fine model results. The results of coarse models were treated statistically to quantify their deviation from the fine models results and rank the upscaling algorithms accordingly. It was found that the depletion process affects the choice of the appropriate upscaling algorithm.
The coarse grid models lose some accuracy with increasing the upscaling ratio, as suspected. Also we found that several upscaling algorithms work equally well in depletion processes. However, only flow-based upscaling techniques (especially with open boundary condition) worked well for water injection processes. For miscible and immiscible gas injection processes, the use of flow based upscaling techniques is generally a must, while the flow-based upscaling technique with closed boundary conditions shows slightly better results than other flow-based upscaling techniques.
For miscible gas injection processes, in particular, the use of which upscaling technique is sensitive to the heterogeneity index as well specially for models with Lorenze Coefficient higher than 0.5.
Real Results of Optimizing Economics and Operations in a Workover Campaign in the Hassi Messaoud Field using Solid Expandables
Authors: Stringer Jordan A. , Saad Marc A. 
Published: February 2012

ABSTRACT
Revitalizing aging fields can be complicated when viewed through an outlook of economic viability versus the associated operational and design risks. However, workover campaigns may be deemed more economically efficient and lower risk with the continuous advancements in technology, especially applicable to smart well designs. Workover projects are becoming ever more viable, with production being optimized through the application of advanced well construction products such as Solid Expandables along with existing brownfield infrastructure.
The operator of the Hassi Messaoud field, one of the largest and oldest onshore oil producing fields in Algeria, embarked on a large scale workover campaign to revitalize this field and optimize oil production from wells which have been drilled over 40 years ago. The typical workover program targeted extending the open-hole below the 7-in. casing across the Cambrian reservoir and completing the wells with a 4-1/2-in liner. Challenges with various formations encountered and the depleted reservoir resulted in the viability of only a slim hole configuration restricting production.
Maximizing the wellbore diameter across the reservoir while isolating higher pressured shale's directly above and balancing the economic return on investment required the inclusion of multiple technologies to achieve the well and production objectives, all using the existing well infrastructure.
A total of 7 wells have been worked over to date since early 2010 which avoided slim-bore configurations through the inclusion of 939m of 5-1/2" expandable tubular maximizing reservoir diameter and serving as a permanent mechanical barrier. The campaign also incorporated underbalanced drilling operations as a tool for mitigating subsequent pressured formations and testing production as required. The actual campaign had a reduction in operational time of 40% while significantly increasing and optimizing production rates.