Thinly Bedded Reservoirs Research Articles

Porosity estimation in the Fort Worth Basin constrained by 3D seismic attributes integrated in a sequential Bayesian simulation framework

The accurate inference of reservoir properties such as porosity and permeability is crucial in reservoir characterization for oil and gas exploration and production as well as for other geologic applications. In most cases, direct measurements of those properties are done in wells that provide high vertical resolution but limited lateral coverage. To fill this gap, geophysical methods can often offer data with dense 3D coverage that can serve as proxy for the variable of interest. All the information available can then be integrated using multivariate geostatistical methods to provide stochastic or deterministic estimate of the reservoir properties. Our objective is to generate multiple scenarios of porosity at different scales, considering four formations of the Fort Worth Basin altogether and then restricting the process to the Marble Falls limestones. Under the hypothesis that a statistical relation between 3D seismic attributes and porosity can be inferred from well logs, a Bayesian sequential simulation (BSS) framework proved to be an efficient approach to infer reservoir porosity from an acoustic impedance cube. However, previous BBS approaches only took two variables upscaled at the resolution of the seismic data, which is not suitable for thin-bed reservoirs. We have developed three modified BSS algorithms that better adapt the BSS approach for unconventional reservoir petrophysical properties estimation from deterministic prestack seismic inversion. A methodology that includes a stochastic downscaling procedure is built and one that integrates two secondary downscaled constraints to the porosity estimation process. Results suggest that when working at resolution higher than surface seismic, it is better to execute the workflow for each geologic formation separately.

A fully coupled numerical modeling to investigate the role of rock thermo-mechanical properties on reservoir uplifting in steam assisted gravity drainage

One of the crucial consequences of steam assisted gravity drainage (SAGD) process is abnormal reservoir uplifting under thermal steam injection, which can significantly influence the reservoir rock deformation, specifically thin bed reservoirs and causes intensive failures and fractures into the cap rock formations. A thorough understanding of the influences of rock thermo-mechanical properties on reservoir uplifting plays an important role in preventing those aforementioned failures within design and optimization process in SAGD. In addition, coupling of reservoir porous medium and flowing of specific fluid with temperature as an additional degree of freedom with initial pore pressure and in-situ stress condition, are also very challenging parts of geomechanical coupled simulation which would be clearly explained. Thus, a fully coupled thermo-poro-elastic geomechanical model with finite element codes was performed in ABAQUS to investigate the role of rock thermo-mechanical parameters on reservoir vertical uplift during steam injection. It is clearly observed that, any increase in rock thermo-mechanical properties specifically rock’s thermal properties such as specific heat, thermal expansion, and formation’s thermal conductivity, have significant influences on reservoir uplift. So by coupling the temperature as an additional degree of freedom with the coupled pore-fluid stress and diffusion finite element model of SAGD process, the more realistic simulation will be conducted; hence, the errors related to not having heat as an additional degree of freedom will be diminished. In addition, Young’s modulus and specific heat are the rock thermo-mechanical parameters which have the maximum and minimum effects on the reservoir uplift, respectively.

Integrating Old and New Data-Evaluation Techniques for Effective Reservoir Characterization of Southeastern Niger Delta Reservoirs

Summary The value of data integration has been proved in assessing the thin-bedded H4 reservoir and the stratigraphically natured H5 reservoir in UKU Field, southeastern Niger Delta, toward planning effective development strategies for depletion. Reservoirs of these definitions pose problems during mapping from seismic for well planning and drilling activities, as well as at the production stage. Data for this work consist of a recently acquired full-stack, 3D ocean-bottom-cable (OBC), prestack-time-migrated (PSTM) seismic data; well logs from five vertical wells; core information; and modular-dynamic-test (MDT) data. Seismic-attribute maps and extracted geobodies revealed the reservoir extent within the limit of seismic resolution (≈27 ft), while petrophysical analysis indicates the reservoirs to be of excellent flow-and-storage quality. MDT data reveal the hydrocarbon fill to be of medium-to-heavy grade. While water production was decided not to be probable for H4 reservoir depletion, it is of certainty in H5 reservoir production. Mapping showed that the field is separated into two fault blocks (FB1 and FB2) on the basis of the difference in water-contact levels, with calculated oil volume of 4 million BO (FB1) and 12 million BO (FB2) in H4 reservoir and 12 million BO (FB1) and 2 million BO (FB2) in H5 reservoir. Gas reserves in H4 sand were calculated to be 480 MMcF in FB2.

Thin-bedded reservoir analogs in an ancient delta using terrestrial laser scanner and high-resolution ground-based hyperspectral cameras

Ground-based terrestrial laser scanning and hyperspectral sensors were used to image fine-scale heterogeneity in outcrops of prodeltaic heterolithic facies of Parasequence 6 of the Cretaceous Ferron Notom delta in Southern Utah. Previous work shows that Parasequence 6 is an upward coarsening fluvial-dominated, wave-influenced deltaic deposit containing heterolithic thin-bedded facies representing distal delta front and proximal prodelta environments. Primarily, the thin beds have been interpreted as turbidites, storm beds (tempestites), and hyperpycnites. These deposits represent analogs for thin-bedded unconventional pay zones that lie at the margins of conventional deltaic sandstone reservoirs.The terrestrial laser scanner was used to create a centimeter- to decimeter-scale, digital representation of the outcrops in three dimensions. Hyperspectral sensors record electromagnetic radiation reflected off the outcrops in 840 contiguous bands, which were then used to generate a spectral signature for each pixel sampled. The spectral signatures are a function of mineralogy, chemistry, surface alteration, grain-size, and cements, and were used to distinguish thin mudstones from sandstones within an interbedded succession at the base of a deltaic parasequence. Comparison between the spectral signatures recorded from the outcrop and those of reference materials, and with previous facies architecture studies, enables lithofacies to be identified and subsequently accurately mapped. Hyperspectral data are then draped over the terrestrial laser scanner model to generate a spatially-accurate detailed three-dimensional (3D) geologic map of the heterogeneity.Approximately 100m of outcrop was imaged laterally with the hyperspectral camera and terrestrial laser scanner on the previously mapped distal delta front and prodeltaic facies of Parasequence 6. Bed thickness data, based on measurements made along depositional dip versus strike, show that bed geometries are anisotropic. Reconstruction of the plan-view geometry shows that the thin-beds are lobate to elongate in plan-view profile and extend over distances of about 1km, indicative of the dispersive waning sediment transport processes found in storm-influenced fluvial-dominated deltas. The lobate geometry suggests that beds are laterally discontinuous, with a width to thickness ratio on the order of <10,000 (i.e. a 10cm bed extends for <1km). The combined terrestrial laser scanner and hyperspectral data provide continuous 3D maps of grain-size and lithology. The maps which emphasize the continuity and dimensions of thin beds are among important factors which impact reservoir behavior.

Bayesian rock classification and petrophysical uncertainty characterization with fast well-log forward modeling in thin-bed reservoirs

Rock typing is critical in deepwater reservoir characterization to construct stratigraphic models populated with static and dynamic petrophysical properties. Rock typing based on multiple well logs is subject to large uncertainty in thinly bedded reservoirs because true physical properties cannot be resolved by low-resolution logging tools due to shoulder-bed effects. We have introduced a new Bayesian approach that inherently adopts the scientific method of iterative hypothesis testing to perform rock typing by simultaneously honoring different logging-tool physics in a multilayered earth model. In addition to estimating the vertical distribution of rock types with maximum likelihood, the Bayesian method quantifies the uncertainty of rock types and the associated petrophysical properties layer by layer. Bayesian rock classification is performed with a fast sampling technique based on the Markov-chain Monte Carlo method, thereby enabling an efficient search of rock types to obtain the final results. We have used a fast linear iterative refinement method to simulate nuclear logs and a 2D forward modeling code to simulate array-induction resistivity logs. A rock-type distribution hypothesis is considered acceptable only when all the observed well logs are reproduced with forward modeling. In a field case of offshore deltaic gas reservoir, the Bayesian method differentiates rock types that exhibit subtle petrophysical variations due to grain size change. The new method provides more than 77% agreement between log- and core-derived rock types, whereas conventional deterministic methods achieve only 60% agreement due to the presence of thin beds and laminations. Even though large uncertainty is observed in thinly bedded and laminated zones, the Bayesian rock-typing method still yields rock types and petrophysical properties that agree well with core-plug measurements acquired in these layers. As a result, the overall correlation between log-derived permeability and core-measured permeability is improved by approximately 16% when compared with conventional deterministic methods.

Subsurface and Petrophysical Studies of Shaly-Sand Reservoir Targets in Apete Field, Niger Delta

Conventional departures from Archie conditions for petrophysical attribute delineation include shaliness, fresh formation waters, thin-bed reservoirs, and combinations of these cases. If these departures are unrecognized, water saturation can be overestimated, and this can result in loss of opportunity. Wireline logs of four (4) wells from Apete field were studied to delineate petrophysical attributes of shaly-sand reservoirs in the field. Shale volume and porosities were calculated, water saturations were determined by the dual water model, and net pay was estimated using field-specific pay criteria. Ten sand units within the Agbada formation penetrated by the wells were delineated and correlated and their continuity was observed across the studied wells. The reservoirs had high volume of shale (Vcl), high hydrocarbon saturation, low water saturation, and good effective porosity ranging 12.50–46.90%, 54.00–98.39%, 1.61–46.0%, and 10.40–26.80%, respectively. The pay zones are relatively inhomogeneous reservoirs as revealed from the buckle’s plot except in Apete 05. The direction of deposition of the sands was thus inferred to be east west. Empirical relationships apply with variable levels of accuracy with observation of the porosity-depth, water saturation-depth, and water saturation-porosity trends. Core data is recommended for better characterization of these reservoirs.

Research and Application of Thermal Insulation and Injection-Production Process Technology in the Shallow and Thin-Bedded Heavy Oil Reservoirs

In view of Shallow and Thin-Bedded Heavy Oil Reservoirs, it belongs to the forbidden zone which can not be developed by the internationally recognized. To reduce the cost of well drilling and well completion, Φ139.7 mm casing is adopted in well completion. In the early Pilot test, there were many problems in steam injection with blank tubing, low thermal efficiency of steam injection, casing and cement mantle damaged seriously, and even as worse as well abandonment. To solve the problems, the Insulated and Injection-Production integration tubing string was designed by the Y341-115 insulation packer and other supporting tools, which can solve wellbore heat insulation and reverse circulation well cleanup in production. It carried out the function that multicycle steam injection and production can be integrated in one-trip. The large scale application showed that the effect of heat insulation was remarkable, which reduced the production cost, made the shallow and thin-bedded heavy oil reservoirs develop economically and effectively.

Statistical analysis of petrophysical parameters of Middle Miocene rocks from the Polish Carpathian Foredeep

Normal 0 21 false false false PL X-NONE X-NONE MicrosoftInternetExplorer4 Sarmatian thin-bedded sandy-shaly formation was a subject of statistical studies to differentiate between good and poor reservoir rocks and to show gas-saturated layers in comparison to water-saturated formation. Statistical studies including fractal analysis were performed on well logging data from well S-34 drilled in a belt of hydrocarbon deposits that continued below the northern edge of the Carpathian-Stebnik overthrust. Lithological variability and porosity differentiation and changes in water saturation were traced on the basis of results of well logging interpretation. Basic statistics and histograms of petrophysical parameters were investigated. A generalized fractal correlation dimension of the second order was calculated for all parameters and analyzed in the same way as time series. Fractal dimensions did not correlated with the parameters, but good positive correlations between them and parameters were observed and proved that the analyzed curves had the same type of complexity. High correlation coefficients showed pairs of fractal dimensions for those parameters which had similar variability and the same curve roughness. Fractal correlation dimension described the type of complexity of the parameter (curve roughness) and indicated, for example, how shaliness influenced the reservoir properties of Middle Miocene. Therefore, the results had also the practical side, which gave extra information on thin-bedded reservoir rock formations. Sarmatian thin-bedded sandstone and shales have been a subject of statistical studies to differentiate between good and poor reservoir rocks and to show gas-saturated layers in comparison to water-saturated strata. Statistical studies including fractal analysis were performed on well logging data from the Sędzisz&oacute;w 34 borehole drilled in a belt of hydrocarbon deposits that continue below the northern edge of the Carpathian&ndash;Stebnik overthrust. Lithological variability and porosity differentiation and changes in water saturation were traced on the basis of the results of well logging interpretation. Basic statistics and histograms of petrophysical parameters have been analysed. A generalized second order fractal correlation dimension was calculated for all parameters and analysed as for a time series. Fractal dimensions did not correlated with the parameters, but good positive correlations between them and the parameters were observed and showed that the curves analysed had the same type of complexity. High correlation coefficients showed pairs of fractal dimensions for those parameters which had similar variability and the same curve roughness. The fractal correlation dimension described the type of complexity of the parameter (curve roughness) and indicated, for example, how shaliness influenced the reservoir properties of the local Middle Miocene. Therefore, the results were also useful in practice, which gave extra information on thin-bedded reservoir rocks. &nbsp;

Technology Focus: Mature Fields and Well Revitalization (January 2011)

Technology Focus Growth in oil and gas production must stem from a combination of new-field development and effective management of existing fields. Substantial additional reserves can be secured by enhancing the recovery from mature fields. Many operators are aggressively pursuing a strategy that is based on tapping bypassed horizons, cutting costs, and implementing leading-edge technologies to combat the natural decline of mature fields. Field exploitation strategies such as resource-targeted infill drilling, field- or play-extension wells, and strategic recompletion, the locations of which are based on integrated-characterization studies, are the preferred approaches to revitalization of mature fields. Reserves growth is enhanced further by deployment of advanced characterization technologies such as 3D seismic that enable better definition of the structural framework of a mature field, enabling targeting of depositional axes for strategic infill drilling. An integrated approach built on the latest reservoir-management and production-enhancement techniques promises to accelerate the revitalization of mature fields. Production-enhancement techniques such secondary and tertiary schemes, horizontal and multilateral drilling, improved perforation and stimulation methods, new completion techniques, advanced logging procedures, artificial-lift optimization, and water control can boost the recovery from mature fields. Papers selected for this feature are aligned with the aforementioned theme of integrated reservoir management and production enhancement. Mature Fields and Well Revitalization additional reading available at OnePetro: www.onepetro.org SPE 134061 • “An Integrated Analytical Method for Identifying Remaining Potential of a Thin-Bed Reservoir in a Deltaic System—Sengata Field” by Riswan Kiay Demak, Pertamina, et al. SPE 135921 • “Technological Solutions for Marginal-Oilfield Development” by Ravil R. Ibatullin, SPE, TatNIPIneft, et al. SPE 128448 • “Optimizing Simulation Studies for Gas/Condensate-Field Development and Management” by Ahmed El-Banbi, SPE, Cairo University. SPE 132187 • “Using Drilling and Logging Data for Developing 1D Mechanical Earth Model for a Mature Oil Field To Predict and Mitigate Wellbore-Stability Challenges” by M. Afsari, Iranian Offshore Oil Company, et al.

Predicting the distribution of thin bed reservoirs by broad frequency band seismic

Recognition of thin interbedded reservoirs in the middle-shallow strata in the Songliao Basin is a great difficulty. In order to resolve this problem, we present a technique for predicting the distribution of thin reservoirs using a broad frequency band and ultra high resolution seismic. Based on forward modeling, we recognized that a thin bed seismic reflection is characterized by changing amplitude with changing frequency (amplitude versus frequency, AVF). We calculate the thickness of thin reservoirs from their AVF characteristics and predict the distribution of thin bed reservoir using broad frequency band and ultra high resolution seismic. The technique has been applied in the 3D seismic area of Zhaoyuan in the northern part of the Songliao Basin. The seismic resolution is increased by two or three times over that of conventional seismic and many thin reservoirs have been identified. The technique has extensive application to the exploration and development of oil and gas, such as optimizing the location of exploration wells, the design of wells (especially horizontal wells), choice of production test layers, analyzing reservoir continuity in development wells, and so on.

Multi-component AVO response of thin beds based on reflectance spectrum theory

Seismic AVO analysis now is one of the major criteria for recognizing potential hydrocarbon reservoirs. Volume scattering information that carries information of stratigraphic structure, lithology, and pore fluid is more useful for seismic exploration. However, traditional AVO analysis is based on the Zoeppritz equation, which only contains single-interface information. Quantitative interpretation of the thin bed thickness is essential to thin bed structure interpretation, reservoir description, and lateral reservoir prediction. The reflectance spectrum equation based on the elastic wave propagation matrix in the frequency domain derived in this paper shows that both interfaces and intervals have an effect on amplitude. The equation includes information about both single interfaces and ' volume scattering. Since the reflectance spectrum equation is a continuous function of thin bed thickness and frequency, it is convenient to analyze the effects of a single frequency and bed thickness on the reflectance spectrum. Bed thickness is analyzable until the bed thickness is vanishingly small. These characteristics can't be achieved by Fourier transform. The propagation of seismic waves is complex and various wave modes exist simultaneously. The reflectance spectrum includes various propagating wave modes and multiples and is better for simulating multi-component thin bed AVO responses than the ray tracing method.

An unusual, muddy, epeiric carbonate reservoir: The Lower Muschelkalk (Middle Triassic) of the Netherlands

The mud-dominated Lower Muschelkalk carbonates (Middle Triassic) are a unique reservoir currently producing gas in the Dutch De Wijk field. Numerous gas shows scattered over the Netherlands onshore and offshore suggest further, currently unrecognized potential. This study complements an extensive subsurface data set with selected outcrop information to localize missed opportunities and evaluates the factors controlling the development of this unusual reservoir type. The muddy carbonates are deposits of a storm-dominated, epeiric carbonate ramp with negligible depositional gradient. Different marlstone, dolomudstone, and lime mudstone facies types reflect the low-energy coastal-plain to inner ramp and higher energy midramp to proximal outer ramp depositional environments. The best reservoir facies is recognized in distal inner ramp algal dolomudstones (porosity up to 24% and permeability up to 32 md). Because of the variable intensity of early, facies-related diagenesis, the reservoir quality of dolomudstones decreases markedly in landward and seaward direction from the distal inner ramp. The stacking of decimeter- to meter-thick reservoirs is reflected by a fourfold hierarchy of depositional cycles that can largely be recognized with conventional wire-line logs. High-resolution outcrop and subsurface correlations reveal that stacks of thin-bedded reservoir units most probably pinch out within a few kilometers, and that their lateral continuity should not be overestimated despite the epeiric layer-cake setting. Local reservoir occurrences are commonly situated above paleohighs of tectonic or halokinetic origin. Not only the reduced thickness of the Lower Muschelkalk above these paleohighs, but also the presence and lateral extent of local reservoirs, might be detected with seismic data. The general facies and reservoir patterns exemplified by the Lower Muschelkalk may also be of use for reservoir prediction in similar epeiric settings elsewhere, for instance, in the Middle East.

Comparing deterministic and stochastic seismic inversion for thin-bed reservoir characterization in a turbidite synthetic reference model of Campos Basin, Brazil

The inversion of seismic data for acoustic impedance is a frequently used technique because it offers several advantages:

Analysis and numerical modelling of wireline pressure tests in thin-bedded turbidites

This paper presents new insights in modelling wireline transient pressure tests in thin-bedded turbidites (TBTs). Permeability heterogeneities are classically evaluated from core measurements and through geological description of the reservoir, then possibly refined by simulation and history matching. Wireline formation testing (WFT) is shown to offer the possibility to obtain these details at an intermediate scale, readily available for input in flow simulators. This is critical in complicated multilayered, thin-bedded reservoir, which cannot be adequately described with conventional, logs, cores and well tests. Numerically simulated pressure responses from straddle packer tests, modelled using image logs, are matched with measured ones and the method enables the determination of permeabilities of the straddled layers. Simulation is required as no analytical solution exists for direct transient pressure analysis in these layered systems. A real case illustrates the methodology used, and we show that in such deep marine environments possible lateral geological variations are deduced from transient pressure analysis, such as sand pinching out or lensing, which could not be inferred from other static measurements. We highlight through this example and sensitivity simulations of geological effects that this technique offers an economical alternative to more traditional coring or well testing. We also discuss the potential pitfalls associated with poor acquisition designs, short test duration and the nonuniqueness of the inversion problems.

Frequency-enhanced imaging of stratigraphically complex, thin-bed reservoirs: A case study from South Marsh Island Block 128 Field

Application of a poststack processing method that separates signal from noise, while enhancing only the high frequency “earth signal,” helped identify new well locations in thinly bedded reservoirs that would not have otherwise been drilled. More importantly, wells drilled after application of this method added significant new reserves to a 27-year-old, offshore Gulf of Mexico field and nearly quadrupled daily production rates.

ABSTRACT: Advanced Thin-bed Reservoir Characterization Using Integrated 3-D Seismic And Well Data

ABSTRACT: Advanced Thin-bed Reservoir Characterization Using Integrated 3-D Seismic And Well Data

Potential for Horizontal-Well Technology in the U.S.

Summary Application of horizontal wells has increased tremendously and had significant and positive results in the U.S. over the past decade. The pace of horizontal drilling for oil has remained high since 1990 (approximately 600 to 1,000 wells/yr). Most of these wells have been drilled in three formations: the Austin chalk in Texas (79%), the Bakken shale in North Dakota (5%), and the Niobrara in Colorado and Wyoming (2%). Wells drilled in other formations constitute approximately 14%. The Dept. of Energy Natl. Petroleum Technology Office (DOE/NPTO), working closely with industry, developed a unique analytical system (including models and database) to assess the potential for wider application of this technology to the balance of remaining U.S. oil resources across a variety of formations. The findings of the DOE effort are the primary scope of this paper. Introduction The DOE/NPTO developed a comprehensive analytical system for evaluation of horizontal-well potential in the lower 48 U.S. states. The system is intended for use in association with other improved-oil-recovery methods that make up the DOE's Total Oil Recovery Information System (TORIS). The Natl. Petroleum Council initially developed the TORIS system in 1984 for its nationwide enhanced-oil-recovery assessment. Since 1984, the DOE/NPTO has maintained and operated the system as a planning and analysis tool to address important policy issues regarding R&amp;D, economic incentives, and environmental regulations for the U.S. Congress, state and federal government agencies, industry associations, and U.S. oil and gas operators. In 1997, the DOE/NPTO worked very closely with a coalition of industry representatives to identify the target resource for horizontal-well technology and evaluate its future recovery potential under several economic and technological scenarios. The industry coalition included representatives from majors and independent producers, service companies, and industry associations. This paper first gives a brief overview of horizontal-well activities to date, then focuses on the approach, method, and rationale for the analytical system. In addition, the paper provides a national summary of additional production and reserves possible with more-diverse application of horizontal wells in various types of U.S. oil resources. This includes the balance of naturally fractured reservoirs in the Austin chalk, other fractured reservoirs in the north and northwestern states, thin-bed reservoirs, and mature waterflood fields to improve sweep efficiency by means of injection-profile modification or horizontal infill wells. All results are presented in terms of production, reserves, and national economic benefits, with full cash-flow analysis at oil prices in the U.S. $16 to $24/bbl range. Scope of the Analysis Since 1990, the pace of drilling horizontal oil wells has remained high at approximately 600 to 1,000 wells/yr (Fig. 1).* The greatest use of horizontal wells in the lower 48 states, however, has been for development of naturally fractured reservoirs, particularly those in the prolific Austin chalk (Fig. 2).*,1 These reservoirs often consist of "compartments" that are long and parallel or subparallel to natural vertical fractures from which oil or gas can be produced. Vertical wells drilled into these compartments have limited chance of success because it is unlikely that the well will penetrate more than one or two compartments. Horizontal wells, on the other hand, can be drilled several thousands of feet laterally through the formation to connect multiple fractures or compartments to the wellbore, greatly improving the chance of achieving commercial oil or gas production. Moreover, horizontal wells have the ability to produce at relatively high rates with low pressure differential between the reservoir and the well. These factors, along with favorable geometry, make horizontal wells very attractive for application in reservoirs with water- and gas-coning problems. Approximately one-third of horizontal wells in the U.S. have been drilled to minimize coning.2 With continued and steady development of horizontal-drilling technology and development of more-effective diagnostic tools, we envision that application of horizontal wells will become more diverse, particularly in the following areas.Thin-Bed Reservoirs. Horizontal wells can be highly beneficial in development of thin-bed reservoirs (less than 25 ft of net pay) or marginally productive reservoirs (low permeability or porosity). The increased wellbore exposure in these reservoirs results in much higher well productivity with horizontal wells compared with that of vertical wells, making production at economical rates possible.3Injection-Profile Modification. Horizontal wells also can be used to improve volumetric sweep efficiency in new or existing waterfloods with poor injection profiles. Horizontal drilling can be used to place laterals from vertical injectors into zones of lower injectivity, which allows water to enter these zones more easily and to displace and produce a significant volume of oil that might have remained unrecovered otherwise.

Abstract: An Integrated Outcrop and Behind Outcrop Study of Slope San (Channel-levee) Lithofacies, Taranaki, New Zealand, and Their Implications to Thin-Bedded Reservoirs

Abstract: An Integrated Outcrop and Behind Outcrop Study of Slope San (Channel-levee) Lithofacies, Taranaki, New Zealand, and Their Implications to Thin-Bedded Reservoirs

Improvement on the Evaluation of Thinly Bedded Reservoir Using Borehole Images in Honzontal Wells. : ABSTRACTS

Improvement on the Evaluation of Thinly Bedded Reservoir Using Borehole Images in Honzontal Wells. : ABSTRACTS

Slope Fan Turbidites from the Mt. Messenger Formation, Taranaki, New Zealand with Applications to Thin-Bedded Reservoirs : ABSTRACTS

Slope Fan Turbidites from the Mt. Messenger Formation, Taranaki, New Zealand with Applications to Thin-Bedded Reservoirs : ABSTRACTS