No description available.

Characterization of carbonate reservoirs by flow units is a practical way of reservoir zonation. This study represents a petrophysical-based method that uses well loggings and core plug data to delineate flow units within the most productive carbonate reservoir of Derdere Formation in Y field, Southeast Turkey. Derdere Formation is composed of limestones and dolomites. Logs from the 5 wells are the starting point for the reservoir characterization. The general geologic framework obtained from the logs point out for discriminations within the formation. 58 representative core plug data from 4 different wells are utilized to better understand the petrophysical framework of the formation. The plots correlating petrophysical parameters and the frequency histograms suggest the presence of distinctive reservoir trends. These discriminations are also represented in Winland porosity-permeability crossplots resulted in clusters for different port-sizes that are responsible for different flow characteristics. Although the correlation between core plug porosity and air permeability yields a good correlation coefficient, the formation has to be studied within units due to differences in port-sizes and reservoir process speed. Linear regression and multiple regression analyses are used for the study of each unit. The results are performed using STATGRAPH Version Plus 5.1 statistical software. The permeability models are constructed and their reliabilities are compared by the regression coefficients for predictions in un-cored sections. As a result of this study, 4 different units are determined in the Derdere Formation by using well logging data, and core plug analyses with the help of geostatistical methods. The predicted permeabilities for each unit show good correlations with the calculated ones from core plugs. Highly reliable future estimations can be based on the derived methods.

Magister Scientiae - MSc (Earth Science) / The Orange basin is relatively underexplored with 1 well per every 4000km2 with only the Ububhesi gas field discovery. Block 1 is largely underexplored with only 3 wells drilled in the entire block and only well A?F1 inside the 1500km2 3?D seismic data cube, acquired in 2009. This study is a reservoir characterization of well A?F1, utilising the acquired 3?D seismic data and re?analysing and up scaling the well logs to create a static model to display petrophysical properties essential for reservoir characterization. For horizon 14Ht1, four reservoir zones were identified, petro?physically characterized and modelled using the up scaled logs. The overall reservoir displayed average volume of shale at 24%, good porosity values between 9.8% to 15.3% and permeability between 2.3mD to 9.5mD. However, high water saturation overall which exceeds 50% as per the water saturation model, results in water saturated sandstones with minor hydrocarbon shows and an uneconomical reservoir.

Master of Science / Department of Geology / Abdelmoneam Raef / Seismic reservoir characterization and prospect evaluation based 3D seismic attributes analysis in Kansas has been successful in contributing to the tasks of building static and dynamic reservoir models and in identifying commercial hydrocarbon prospects. In some areas, reservoir heterogeneities introduce challenges, resulting in some wells with poor economics. Analysis of seismic attributes gives insight into hydrocarbon presence, fluid movement (in time lapse mode), porosity, and other factors used in evaluating reservoir potential. This study evaluates a producing lease using seismic attributes analysis of an area covered by a 2010 3D seismic survey in the Morrison Northeast field and Morrison field of Clark County, KS. The target horizon is the Viola Limestone, which continues to produce from seven of twelve wells completed within the survey area. In order to understand reservoir heterogeneities, hydrocarbon entrapment settings and the implications for future development plans, a seismic attributes extraction and analysis, guided with geophysical well-logs, was conducted with emphasis on instantaneous attributes and amplitude anomalies. Investigations into tuning effects were conducted in light of amplitude anomalies to gain insight into what seismic results led to the completion of the twelve wells in the area drilled based on the seismic survey results. Further analysis was conducted to determine if the unsuccessful wells completed could have been avoided. Finally the study attempts to present a set of 3D seismic attributes associated with the successful wells, which will assist in placing new wells in other locations within the two fields, as well as promote a consistent understanding of entrapment controls in this field.

Submitted by RICARDO OTTO ROZZA SCHMIDT null (rottoschmidt@gmail.com) on 2016-06-20T16:57:36Z No. of bitstreams: 1 Mestrado Dissertação Final_Dig.pdf: 14191761 bytes, checksum: dbea65724bee20d777cf130e21a9ab56 (MD5) / Approved for entry into archive by Ana Paula Grisoto (grisotoana@reitoria.unesp.br) on 2016-06-23T14:12:58Z (GMT) No. of bitstreams: 1 schmidt_ror_me_rcla.pdf: 14191761 bytes, checksum: dbea65724bee20d777cf130e21a9ab56 (MD5) / Made available in DSpace on 2016-06-23T14:12:58Z (GMT). No. of bitstreams: 1 schmidt_ror_me_rcla.pdf: 14191761 bytes, checksum: dbea65724bee20d777cf130e21a9ab56 (MD5) Previous issue date: 2016-05-03 / Os arenitos de água profunda, designados genericamente como turbiditos, têm enorme relevância energética e econômica para o Brasil. Na Bacia de Campos, a maior parte dos campos produtores contêm níveis turbidíticos da Formação Carapebus (Eoceno), focalizados neste estudo. É o caso dos campos de Enchova e Bonito. Nesta dissertação propõe-se a caracterização geológica-petrofísica dos reservatórios turbidíticos (Eoceno) nestes campos, que mesmo descobertos há 30 anos detém poucas informações publicadas no que se refere à sua disposição espacial litológica e petrofísica. A integração de metodologias e ferramentas possibilita a melhor compreensão dos reservatórios e de suas heterogeneidades. Neste trabalho foram integrados dados oriundos de testemunhos, perfis de poços, sísmica 3-D (40 km²) por meio dos métodos geoestatísticos Krigagem Indicativa e Krigagem Ordinária, de forma a contribuir com o entendimento da distribuição das principais unidades do reservatório. A análise litológica teve como enfoque os métodos qualitativos, apoiada na descrição de testemunhos apresentadas na pasta de poço, e quantitativo, baseado nas análises dos perfis geofísicos de 20 poços. Com base nesta correlação rocha-perfil, os litotipos arenito, carbonato e folhelho foram definidos e extrapolados para os intervalos não testemunhados. A interpretação e correlação dos perfis geofísicos identificaram dois níveis arenosos principais, o inferior com 10 a 15 m e superior com 70 a100 m, separados por uma camada de folhelho de 5 a 20 m. Salienta-se o controle deposicional de uma feição erosiva de idade Maastrichiano-Eoceno Médio, a qual concentra as maiores espessuras de areia a oeste dos campos. A caracterização estrutural do reservatório, definida por três feições dômicas alinhadas a NE, foi definida pela interpretação sísmica 3-D. A análise de atributos sísmicos de amplitude, realizada no intervalo definido entre os horizontes topo e base do reservatório, revelou geometrias associadas a complexos de canais discretos, em Enchova, e lobos canalizados, em Bonito. O modelo litológico do reservatório obtido pela aplicação da Krigagem indicativa representou satisfatoriamente os níveis turbidíticos quando comparados aos dados de poços e mapas atributos sísmicos, que indica as maiores espessuras dos turbiditos a oeste das áreas. O modelo da porosidade obtido pela Krigagem Ordinária (Krigagem Indicativa) indicou melhores condições porosas na porção oeste dos campos, correlacionando-se com o modelo litológico carbonatos fechados e folhelhos no modelo litológico. Ambos, os mapas de atributos sísmicos e modelos obtidos apresentam uma área com potencial exploratório a sul de Bonito, ainda não perfurada segundo a ANP. / Deep-water sandstones, known as turbidites, play an important role in Brazil's energy and economic scenario. In the Campos Basin, Carapebus Formation´s Eocene turbidites produce in most oil fields of the basin. Enchova and Bonito oil fields, focused in this study, represent Eocene sandstone production areas. Discovered 30 years ago, Eocene reservoirs have a lack of information regarding its lithological and petrophysical distribution. This master thesis proposes a geological-getrophysical reservoir characterization of Eocene turbidites on Enchova and Bonito fields. The integration of methodologies and tools enables a better understanding of the reservoir geometry and heterogeneity. This work integrates core descriptions from well reports, well logs and 3-D seismic through Indicator Kriging (lithology) and Ordinary Kriging (porosity) resulting in 3-D solid models. The models possibly a better understand of lithologic and petrophysical reservoir distribution. The lithological analysis is supported by qualitative methods, supported by the 70m core description provided with well log data, and quantitative, based on the analysis of 20 well logs. Based on this correlation between logs and rocks, the lithology classes, sandstone, carbonate and shale, were defined. The well-logs interpretation and correlation identified two main turbidite intervals, the lower 5 to 15 m and upper 70 to 100 m, separated by a shale layer 5 to 20 m. These intervals were depositionally controlled by an erosive feature associated with Maastrichtian-Middle Eocene unconformity, defining the distribution pattern of turbidites sands concentrated on the western portion of the fields. The reservoir structural characterization, performed trough 3-D seismic interpretation, is defined by three domal features separated by normal faults aligned to NE-SW. Seismic amplitude attributes calculated under the reservoir interval revealed channelized geometries on Enchova field and lobate architecture on Bonito field. The reservoir lithological model obtained through Indicator Kriging demonstrate coherence when compared to well data distribution and seismic attributes maps that indicate turbidite greatest thicknesses in western areas. The model of porosity obtained by Ordinary Kriging revealed best porosity conditions in the western portion of the fields, corresponding to the seismic attributes responses and lithological model. Both geostatistical models and seismic attributes maps revealed an interesting non drilled area located on south of Bonito field.

Seismic inversion is the leading method to map and quantify changes in time-lapse (4D) seismic datasets, with applications ranging from monitoring hydrocarbon-producing fields to geological CO2 storage. However, the process of inverting seismic data for reservoir properties is a notoriously ill-posed inverse problem due to the band-limited and noisy nature of seismic data. This comes with additional challenges for 4D applications, given the inaccuracies in the repeatability of time-lapse acquisition surveys. Consequently, adding prior information to the inversion process in the form of properly crafted regularization terms is essential to obtain geologically meaningful subsurface models and 4D effects. In this thesis, I propose a joint inversion-segmentation algorithm for 4D seismic inversion, which integrates total variation and segmentation priors as a way to counteract the missing frequencies and noise present in 4D seismic data. I validate the algorithm with synthetic and field seismic datasets and benchmark it against state-of-the-art 4D inversion techniques. The proposed algorithm shows three main advantages: 1. it produces high-resolution baseline and monitor acoustic impedance models, 2. by leveraging similarities between multiple seismic datasets, the proposed algorithm mitigates the non-repeatable noise and better highlights the real seismic time-lapse changes, and 3. it simultaneously provides a volumetric classification of the acoustic impedance 4D difference model based on user-defined classes, i.e., percentages of seismic time-lapse changes. Such advantages may enable more robust stratigraphic/structural and quantitative 4D seismic interpretation and provide more accurate inputs for dynamic reservoir simulations.

The Lower Triassic Sinbad Limestone Member of the Moenkopi Formation has produced minor amounts of oil in the Grassy Trail Creek field near Green River, Utah and is present below much of central Utah including the recently discovered Covenant field. Superb outcrops of this thin (15 m), mixed carbonate-silicilastic unit in the San Rafael Swell permit detailed analysis of its vertical and lateral reservoir heterogeneity. Vertically, the Sinbad Limestone comprises three facies associations: (A) a basal storm-dominated, well-circulated skeletal-oolitic-peloidal limestone association, (B) a storm-dominated, poorly-circulated hummocky cross-stratified siliciclastic/peloidal association, and (C) a capping peritidal cross-bedded oolitic dolograinstone association. Eleven microfacies are present in 14 measured sections within the Sinbad Limestone. Lateral variation is most pronounced in the upper part of the basal limestone where storm-deposited beds pinch out over a lateral distance of one kilometer. Otherwise, individual beds and microfacies display a large degree of lateral homogeneity and regional persistence. Diagenesis is strongly controlled by microfacies. Diagenetic elements include marine fibrous calcite cements, micritized grains, compaction, dissolution and neomorphism of aragonite grains, meteoric cements, pressure dissolution, and dolomitization. The paragenetic sequence progresses from marine to meteoric to burial. Marine and meteoric cements occlude much of the depositional porosity. Hydrocarbon-lined interparticle and separate vug (largely molds) pores (1-5%) characterize the skeletal-oolitic limestones with permeability ranging from 0-100 md. Low permeability/porosity characterizes the middle silicilastic unit. The best reservoir qualities (permeability 400 md) occur in portions of the dolomitized oolitic grainstones that form the upper 2 to 3 m of the Sinbad Limestone. Fracture analysis of the studied area indicates a strong NW-SE trend. Fracture spacing is associated with lithology. Fracturing of limestone possibly displays a higher dependence upon bed thickness and microfacies type. The degree of dolomitization controls and increases fracture spacing while siltstones display more closely spaced fractures. The basal limestone unit is an oil storage unit, medial siltstones are flow baffles/barriers, and the dolostone caprock is an oil flow unit. If good connectivity through fractures can be obtained between the dolostone and limestone units, the Sinbad Limestone has potential to serve as a reservoir. This study will not only aid in future Sinbad exploration, but will serve as a model for parasequence-scale intervals in thicker mixed carbonate-siliciclastic successions.

Understanding thickness variation and facies transitions in the mudstone-rich part of the Upper Middle Jurassic (Callovian) Entrada Sandstone depositional system is critical for constraining the paleogeography and evaluating the economic potential of Utah's Entrada Sandstone. Facies of the Entrada Sandstone in south-central Utah are dominated by mudstone-rich intertidal facies that were widespread within the Jurassic seaway. Intertidal deposits interfinger basinward with subtidal ooid-bearing shoals and bars, and landward supratidal sabkha, and erg-margin eolian deposits. Three sections were measured to improve understanding of the lateral and vertical facies transitions. Variations in thickness indicate the rate of developing accommodation space was high along the southwestern shoreline and relatively low along the northeastern shoreline during Callovian time. Although accommodation space was highest in the west, sediment supply from the west kept pace with, and eventually outpaced subsidence. In the east, sediment supply was significant but at one time was outpaced by subsidence, creating a complete range of facies, from subtidal to supratidal deposits. Along this eastern shoreline, erg-margin coastal dunes associated with the larger erg to the east eventually prograded westward. The variation in subsidence, sediment supply, and sediment source makes sequence stratigraphic correlation difficult. Reservoir-quality sandstones are associated with muddy sections of the Entrada Sandstone within the San Rafael Swell. Porosity and permeability of the facies in this area indicate excellent reservoir potential in three of eight facies that were studied. Porosities of these potential reservoirs ranged from 11-22%, with permeabilities ranging from 44-430md. These high quality reservoir facies are surrounded by muddy, low reservoir-quality rocks, creating conditions amenable to the development of stratigraphic hydrocarbon traps. Based on further study and a modern analog at the north of the Gulf of California, Hicks and others' (2010) depositional model for the Entrada Sandstone of south-central Utah has been modified to include newly interpreted facies. This improved depositional model may have predictive power in exploring for stratigraphic and combination traps within the Entrada system of Utah and analogous depositional systems throughout the world.

No description available.

The CO2SINK (and CO2MAN) project is the first onshore CO2 storage project in Europe. The research site is located near the town of Ketzin, close to Potsdam in Germany. Injection started in June 2008, with a planned injection target of 100,000 tonnes of CO2. In February 2011, around 45, 000 tons of CO2 had been injected into the saline aquifer at an approximate depth of 630 m. This thesis focuses on time-lapse analysis of borehole seismic data, surface seismic data and reservoir characterization at the Ketzin site. Baseline Moving Source Profiling (MSP) data were acquired in the borehole Ketzin 202/2007 (OW2), along seven lines in 2007. The zero-offset Vertical Seismic Profile (VSP) data were acquired in the same borehole. The main objective of the VSP and MSP survey was to generate high-resolution seismic images around the borehole. After modeling and data processing, the sandy layers within the Stuttgart Formation can potentially be imaged in the VSP and MSP data whereas reflections from these layers are not as clearly observed in the 3D surface seismic data. 2D and pseudo-3D time-lapse seismic surveys were conducted at the Ketzin site. Interpretation of 2D baseline and repeat stacks shows that no CO2 leakage related time lapse signature is observable where the 2D lines allow monitoring of the reservoir. This is consistent with the time-lapse results of the 3D surveys showing an increase in reflection amplitude just centered around the injection well. The results from the pseudo-3D surveys are also consistent with the 3D seismic time-lapse studies and show that the sparse pseudo-3D geometry can be used to qualitatively map the CO2 in the reservoir with significantly less effect than the full 3D surveying. The 2nd pseudo-3D repeat survey indicates preferential migration of the CO2 to the west. There are no indications of migration into the caprock on either of the repeat surveys. Amplitude Versus Offset (AVO) analysis was performed on both 2D and 3D repeat surveys. A Class 3 AVO anomaly is clearly observed on the 3D repeat data and matches the synthetic modeling well. No AVO anomaly was observed on the 2D repeat data, which was anticipated, but the result shows signs of a pressure response at the reservoir level in the data. Reflection coefficients were calculated using surface seismic data (3D and pseudo-3D) at the site. Pre-injection calculations agree well with calculations from logging data. Post-injection calculations are in general agreement with the seismic modeling, but generally show higher amplitudes than those expected. The full 3D data show a better image of the reflection coefficients before and after injection than the pseudo-3D data and can potentially be used to make quantitative calculations of CO2 volumes. The pseudo-3D data only provide qualitative information.