Carbonate Reservoir Characterization

In this study was analysed thin sections and plugs from the facies of Jandaira Formation, a Turonian-
Campanian carbonate platform in the Potiguar Basin. The focus was in samples from the Rosario outcrop
and a few boreholes. Textural features, framework composition, diagenetic processes, and porosity types
was determined. Were also measured petrophysical properties as permeability and porosity. With
petrografic and petrophysical data we can produce a detail map to support structural and karst analyses in
the study area.

Two giant fields composing of the Oligo-Miocene carbonates and reefs have been discovered recently in the East Java Basin. They are the Bukit Tua-Jenggolo (Gulf/ConocoPhillips Ketapang,
2001) and the Banyu Urip (ExxonMobil Cepu, 2001). These two fields represent the Kujung-
Prupuh carbonate sedimentation on the land-attached platform and the offshore isolated platform, respectively. Geologic factors leading to the formation of giant field is presented and general lessons are outlined. It is obvious that geology and petroleum system’s elements should be crossrelated
for giant field to form. We should be encouraged and comforted in the knowledge that giant fields do exist in the East Java Basin and there are more remain to be found.

West Betara (WB) Field is located in South Sumatra Basin, Indonesia, tested hydrocarbon (Gas) from carbonate reservoirs of the Batu Raja Formation. This is an interesting challenge to describe the lateral distribution and its property within carbonate reservoir at minimum data information. The objectives of this study are to delineate carbonate reservoir distribution including the laterally rock properties by using seismic reservoir characterization methods.

The availability of 3D seismic data, DST's data, conventional well data as wireline and mudlog data is very helpful in answering the challenge. By optimizing well data information, the sensitivity analysis can be generated from wireline log data to determine gas zone and appropriate seismic reservoir characterization method. 3D Seismic data provides a helpful inter-well information for determining and visualizing reservoir structure and rock properties at the present day, they also help us to generate seismic inversion model and multi-attribute analyses to predict reservoir boundary and its property distribution laterally.

The sensitivity analysis of cross-plots combination from Gamma Ray Log, Acoustic Impedance (AI) Log derived from Sonic and density log, Neutron-Porosity Log and Resistivity Log shows good separation for gas zone in carbonate reservoir. The results help us to predict reservoir boundary and its property distribution laterally by seismic inversion and multi-attribute method in our 3D seismic data. The Gamma-ray (low value) and AI (high value) maps are showing consistency of carbonate reservoir delineation. In line with Gamma-ray and AI maps, the porosity map of the carbonate reservoir shows gas zone (high value) with certain pattern and it is consistent with tested well data.

This paper discusses the planning process, execution and lessons learned of an advanced horizontal water injector in a tight carbonate reservoir, onshore United Arab Emirates. The well design required a 10,000 ft horizontal section, to be geosteered in a 6⅛-in. hole through a narrow TVD window of 5 ft, just above the oil water contact.
The challenges were multiple, not only from the rig capability and BHA design point of view, but also from the geosteering and formation evaluation aspects pertaining to borehole hydraulics, completion and stimulation. For injection monitoring analysis the completion had to be run with a perforated 3 1/2-in. stinger design to deploy a 19,500 ft distributed temperature sensing (DTS) system to TD. Four main justifications to execute this pilot project were identified:
• to improve injectivity and therefore the area sweep efficiency in the down flank area of the field
• to segment the wellbore to provide for future selective stimulation along 10,000 ft of horizontal section
• to deploy a DTS system to continuously monitor the water injection profile
• to minimize the number of injection wells in the field, reducing CAPEX, OPEX, surface hook ups and field footprint.
The paper discusses the business case for this project, which includes an initial pilot well containing a 5,100 ft lateral section and four extended reach drilling (ERD) wells, each with a 10,000 ft lateral hole section. Furthermore, best practices from the detailed planning phase to the execution of the first extended reach well are reviewed in this paper.

Carbon dioxide injection in geological formations is currently a common procedure in several reservoirs worldwide. More recently, it has been considered a permanent storage solution, avoiding emission to the atmosphere from large industrial sources. Also, it is largely employed in the oil & gas exploration industry, for enhanced oil recovery (EOR) operations. However, it is a known fact that injection of large amounts of CO 2 into geological reservoirs may lead to a series of alterations due to chemical and physical interactions with minerals and fluids, especially in carbonate or carbonate-rich reservoirs. Experimental and numerical models have been employed in many studies in the past, to investigate these effects on the geological environment. So far, most of these studies focused on siliciclastic formations, whereas carbonate reservoirs, which are known to be much more chemically reactive when interacting with CO 2 , were much less investigated. We present a review of experimental and numerical models that have been employed for studying CO 2-water-rock interactions, and their application to the investigation of the impact in carbonate reservoir quality and integrity caused by the injection of carbon dioxide. C

The growing global campaign and awareness on global warming and climate change and ways of reducing the greenhouse gas emissions into the atmosphere has raised a lot of concern towards ways of possibly reducing the amount of carbon dioxide (CO2) which is a major contributor to global warming within the environment. Over the past few decades, the injection and trapping of carbon dioxide (CO2) gas into petroleum reservoirs like sandstones, shale and carbonates have become a globally accepted enhanced oil recovery technique and an efficient carbon storage process.
Carbonate reservoirs have been studied to contain most of the world’s oil and gas, with the Middle East as one of the major zones dominated by carbonate formations. With carbonate reservoirs understood to have large volumes of oil, there still exist some challenges regarding the recovery of these oil from carbonate reservoirs due to their heterogeneous nature. Some of the challenges identified included early gas breakthrough due to viscous fingering effect of CO2, acid effect of carbonates when in contact with CO2 and reservoir brine, oil recovery challenges due to the effects of CO2 on the reservoir permeability, CO2 injection rates on oil recovery, injection effect of CO2 on oil viscosity and CO2 injection effect on the relative permeability of oil.
This research has been carried out using a typical carbonate reservoir data from a Middle East field. A carbonate reservoir model was developed using Eclipse reservoir simulator software and based on some of the available field data, so as to investigate some of the challenging scenarios experienced in carbonate formations during CO2 injection and their effects on oil recovery factor from the reservoir. The developed eclipse model was set to run on a time-step of 10 years so as to predict the performance of the reservoir over time. Sensitivity studies on oil recovery factor was carried out to examine how changes in CO2 injection rate, CO2 density and reservoir oil density can affect the oil recovery from carbonate reservoirs and to know the most critical effect regarding oil recovery during CO2 flooding. The result shows that CO2 density has the most significant oil recovery at 17.05% followed by the CO2 injection rate with a recovery factor of 16.5% after 10years of production while the oil density has no influence on oil recovery during CO2 injection.

Carbonate sediments within the Mid-Cretaceous Sarvak Formation form an important reservoir at the Abteymour oilfield in the western Dezful Embayment, SW Iran. The poroperm characteristics of this reservoir were controlled by factors including deposition under tropical climatic conditions and early diagenesis, repeated phases of subaerial exposure due to local, regional and global-scale tectonism, and diagenetic modification during burial. From microfacies analysis, the Sarvak Formation carbonates in the Abteymour field were interpreted in a previous study as having been deposited on a homoclinal ramp-type platform. Three third-order sequences were recognized in the middle Cenomanian to middle Turonian part of the formation. The reservoir quality of the carbonates was enhanced both by dissolution (comprising separate phases of eogenetic and telogenetic meteoric dissolution) and dolomitization (especially stylolite-related dolomitization).

In this paper, a rock/pore type approach was used in order to integrate petrophysical data with facies and diagenetic models within a sequence stratigraphic framework. Two different rock-typing methods for the determination of flow units were considered. Hydraulic flow units (HFUs) were identified firstly using flow zone indicators and secondly using a stratigraphic modified Lorenz plot. The flow units resulting from these two methods are compared, and their close correspondence within the sequence stratigraphic framework is discussed. In addition, the previously-used large-scale reservoir zonation scheme for the Abteymour field is correlated with the defined flow units, and four new Integrated Reservoir Zones are introduced. By integrating geological information with petrophysical parameters (including porosity, permeability and saturation) within a sequence stratigraphic framework, field-scale variations and controls on reservoir quality are described.

Knowledge of the magnitude of in situ stresses is crucial to a broad range of applications, particularly drilling, well completion, and hydraulic fracturing design. Stress field characterization is attained by the determination of magnitude and direction of the three principal stresses: the vertical or overburden stress (S v), the minimum horizontal principal stress (S hmin), and the maximum horizontal principal stress (S Hmax). While numerous direct borehole measurements, such as density logs and leak-off tests, provide reliable assessments of S v and S hmin , estimating local S Hmax remains a challenge. This paper presents a workflow that provides with an approach for estimation and constraining of the maximum horizontal principal stress in a carbonate reservoir from borehole sonic logs, by comparison to the isotropic stress state. Our study was restricted to cases with limited achievable data, namely, conventional logs, which is expected to be the circumstances for most practical applications. The results were compared to published regional stress reports, with the goal of validating and understanding the variations of stresses at the field scale. Those findings were in agreement with the estimations obtained from other acoustoelastic methods and the region fault regime in terms of the relative obtained magnitudes of the stresses. In addition to an increasing trend in the calculated stress magnitudes with depth, we observe local variations of stresses in this oilfield, that we suspected to be caused partially by the non-uniform distribution of production and injection activities. The novelty of our proposed workflow is the ability to give borehole estimates of the maximum horizontal principal stress magnitude for a carbonate field located in a regionally compressive zone, without the need for availability of costly measurements, and by taking advantage of techniques to fill in the gaps of limited data, thus, allowing for integrative use of multiple data types that are commonly available.

Ditch cutting samples belonging to Nkporo Formation obtained from depth range of 2462m to 2717m in the Nzam-1 well, Lower Benue Trough were subjected to Total Organic Carbon (TOC) content and Rock-eval Pyrolysis to evaluate their source rock potential for hydrocarbon generation. The samples are made up of shales, sandy shales, mudstone and sandstone. The shales are fissile, fine grained and dark grey in colour while the sandy shales consist of fine grained, fissile and dark grey shales with significant appearance of fine to medium grained, whitish sands. The mudstone is fine grained, grey in colour and blocky (non fissile), while the sandstone is fine grained, compacted and white in colour. The TOC ranges from 0.08 to 1.45 wt. %, indicating that the samples contain appreciable proportion of organic matter that can generate hydrocarbon. Hydrogen Index and Tmax range from 14 mg/g to 37 mg/g and 436°C to 516°C respectively. Genetic Potential (GP), Production Index (PI) and Calculated Vitrinite reflectance (% Ro) range from 0.32 to 0.59 mg/g rock, 0.35 to 0.43 and 0.69 to 2.13 respectively. Rock-eval data indicate that the sediments contain poor to fair source rock for hydrocarbon with kerogen type III as the predominating organic matter, which is capable of generating dry gas. Tmax and other pyrolysis data suggest that the organic matter in the Nkporo Formation is at the peak of thermal maturity to post maturity with respect to hydrocarbon generation. It is concluded that the heat energy generated from post mature part of the studied section together with the thermal maturity peak to late maturity generally observed for the sediments may have resulted in the dry gas prospect.

Primary sweep efficiency in carbonate reservoirs is low due to the low contribution of the matrix in production. Also, due to unfavourable mobility ratio, secondary recovery is not also effective. Hence, design and application of an effective enhanced oil recovery method is essential to improve recovery. Different methods such as water injection, gas injection, chemical injection, thermal, and a combination of these methods such as water alternating gas (WAG), simultaneous WAG (SWAG), selective simultaneous WAG (SSWAG), foam injection, and foam-assisted WAG (FAWAG) are applied to improve the recovery efficiency in naturally fractured reservoirs. In this paper, selection of the best EOR method and well pattern for a naturally fractured reservoir is studied to reach the highest net present value (NPV) and field oil recovery efficiency (FOE). Results showed that the FAWAG process in a five-spot well pattern with 22.7% oil recovery efficiency is the best technical and economical method. Reference to this paper should be made as follows: Bagrezaie, M.A. and Pourafshary, P. (2016) 'Screening and optimisation of water/foam/gas injection EOR scenarios in a fractured reservoir', Int.

Most carbonate reservoirs are commonly characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross of reservoir interval. This heterogeneity complicates the task of reservoir description and thus necessitates the establishment of accurate and detailed understanding of the geological heterogeneities and their impact on petrophysics and reservoir engineering.

Indonesia merupakan salah satu negara yang memiliki cadangan minyak dan gas yang melimpah, dimana sebagian besar lapangan eksplorasi adalah lapangan jenis reservoar batu pasir. Namun seiring dengan bertambahnya kebutuhan maka diperlukan konsep baru yang salah satunya adalah pengembangan reservoar karbonat. Dalam pengembangan reservoar karbonat salah satu yang dibutuhkan adalah estimasi dari porositas efektif reservoar tersebut karena porositas efektif memiliki hubungan langsung terhadap permeabilitas batuan reservoar. Hal ini dibutuhkan untuk menentukan rencana eksplorasi dan produksi ke depannya. Dalam penelitian ini akan dilakukan estimasi porositas efektif pada sumur YN dan MS lapangan "Adhita". Porositas efektif dapat diketahui melalui perhitungan empiris antara densitas, neutron porosity dan gamma ray. Didapat nilai di kisaran 0.02 s/d 0.26 dari perhitungan log sumur YN dan MS. Multi atribut seismik digunakan sebagai input dalam proses neural network dan data log digunakan sebagai target. Jenis neural network yang digunakan adalah supervised back propagation neural network. Persebaran porositas efektif yang diperoleh dari model BPNN dapat memberikan informasi tambahan mengenai kondisi upper carbonate reservoir yang selanjutnya akan digunakan sebagai prakiraan kondisi geologinya. Dari hasil paper ini dapat menghasilkan gambaran persebaran yang lebih relistis tentang estimasi persebarn porositas efektif dan membantu dalam mempelajari gambaran kondisi bawah permukaan. Implikasinya, dapat digunakan untuk kegiatan eksplorasi dan pengembangan hidrokarbon dari lapangan target.

Welcome to the inaugural CSPG-SEPM Mountjoy carbonate meeting, named in honour of Eric Mountjoy. Mountjoy was a legend in the innovative study of limestones and dolomites and in particular understood the importance of discussion and field work for the generation and testing of new ideas. In this spirit the technical committee, along with the session chairs, has worked over the past two years to compile what we hope will be an invigorating program of both talks and field trips that captures the latest developments in carbonate reservoir characterization and modeling. Many of the talks cut across session themes, highlighting the inter-disciplinary nature of our science and the methods used in petroleum exploration and development. We have embedded a number of field trips in the middle of the meeting, as well as a post-meeting field trip. These offer a great opportunity to see some world-class localities in the Canadian Rockies, to network and discuss with other delegates, and to stretch your legs! To conclude the meeting, we are displaying a variety of cores from different carbonate reservoirs at the state-of-the-art Alberta Energy Regulator Core Research Centre in Calgary. In sum, the meeting will have combined more than fifty technical oral and poster presentations, six field trips, and subsurface reservoir rock over five days. Of course, the true success of the meeting is through the participation of delegates-debating ideas, asking questions, sharing experiences, and challenging conventional approaches. We look forward to hearing tales of Eric and how he influenced and inspired folks and the science, and welcome you all to the inaugural Mountjoy meeting.

The Eocene sediments plays critical role in the evolution and development of the petroleum system in the Gulf of Suez region, where it is representing a self-source rock or self-reservoir or combination in some areas within the basin. Microfacies analysis and paleontological studies have not been conducted on these Eocene sediments in the area of the October oil field, which is mandatory for the formation characteristics assessment. Therefore, sidewall core and ditch-cuttings samples that was obtained from October Eocene carbonate sediments so far ascribed to the Thebes formation was studied in terms of sedimentology, paleontology and depositional environment. A total of 64 thin sections were analyzed petrographically, and three microfacies types recognized. Both Calcareous nanoplankton and Foraminifers were examined. The study of the Eocene carbonate facies in the October field revealed that the succession is composed of pelagic foraminiferal limestone of varied color, containing abundant planktonic foraminifers and minor traces of chert. Three microfacies are distinguished including wackestone of smaller planktonic foraminifera (50%), wackestone-packstone of planktonic foraminifera (40%) and packstone of planktonic foraminifera (10%). Nannoplankton and foraminifers indicate that the studied succession is of early Eocene to middle Eocene age. Microfacies and fossil assemblage of the studied section indicate a pelagic environment and deposition in deep basin at water depths of a few hundred meters. Finally, the current results were compared with data from previous publications on Eocene sediments in the region. It is revealed that the studied succession provides new data and contribution for the evolution of carbonate platform in the Ypresian-Lutetian age, and differs from the typical Thebes Formation and other Eocene Formations concerning facies, lithology, fossil content, age and depositional environment. Therefore, we suggest to abandon the term Thebes Formation for this Eocene car-bonate succession in the October field, and a new lithostratigraphic unit, named Radwany Formation, is formally introduced.

West Betara (WB) Field is located in South Sumatra Basin, Indonesia, tested hydrocarbon (Gas) from carbonate reservoirs of the Batu Raja Formation. This is an interesting challenge to describe the lateral distribution and its property within carbonate reservoir at minimum data information. The objectives of this study are to delineate carbonate reservoir distribution including the laterally rock properties by using seismic reservoir characterization methods. The availability of 3D seismic data, DST's data, conventional well data as wireline and mudlog data is very helpful in answering the challenge. By optimizing well data information, the sensitivity analysis can be generated from wireline log data to determine gas zone and appropriate seismic reservoir characterization method. 3D Seismic data provides a helpful inter-well information for determining and visualizing reservoir structure and rock properties at the present day, they also help us to generate seismic inversion model...

The present study investigates the lithofacies and processes such as karstification, which lead to the generation of the karst province of the Neoproterozoic Una and Bambuí groups, located in the central-eastern part of Brazil. This province comprises several systems of carbonate caves (Karmann e Sanchéz, 1979), which include the Toca da Boa Vista and Barriguda caves, considered the largest hypogenic caves in South America (Auler e Smart, 2003).

Sarvak Formation, a thick carbonate succession with the age of Middle Cretaceous, is one of the most significant hydrocarbon reservoirs in the Zagros basin. The Tang-e Solak section of the Sarvak Formation in the Bangestan anticline with a total thickness of about 850 m has been studied, in order to determinate its microfacies types, depositional setting model and depositional sequences. Detailed textural and petrographic analysis led to the identification of 11 microfacies that arranged in three facies associations: inner ramp, mid-ramp, outer ramp and basin. Examination of vertical and lateral facies changes indicated these sediments were deposited in a carbonate ramp depositional system. Frequency analysis of facies indicated outer ramp and basin facies associations are the most frequent facies. Sea level fluctuations during in deposition of Sarvak successions led to formation of two depositional sequences. These depositional sequences are composed of transgressive systems tract and highstand systems tract. The highstand systems tract can be separated into Early HST and Late HST. Stacking pattern in Early HST part is aggradational and in Late HST is progradational.

Carbonate reservoirs are important exploration targets from the perspective of hydrocarbon and, also, groundwater reserves. In this respect, the most important aquifer system in Romania is located in South Dobrogea region, comprising two distinct aquifer complexes: a deeper one, mostly under pressure, hosted in fractured/fissured and karstified limestones and dolomites of Late Jurassic–Early Cretaceous age and a shallower one, mostly unconfined, hosted in Sarmatian (late Middle Miocene) lumachellic and oolitic limestones. The deeper aquifer is regional, confined on more than 60% of its extension, has a SW–NE general flow direction and discharges in Siutghiol Lake (Constanţa city area) and through submarine springs on the Black Sea continental shelf. The water flow occurs through fractures/fissures and dissolution voids within the carbonate rocks and, also, along fault planes.
Although a large number of wells were drilled in South Dobrogea for groundwater exploitation from the Late Jurassic–Early Cretaceous aquifer and, also, for groundwater quality monitoring, there are few published data and studies regarding the geophysical response and petrophysical features of these formations, in relation with their hydrogeological characteristics. The more recent drilling of three hydrogeological research boreholes in the proximity of Cernavodă Nuclear Power Plant (NPP) offered an opportunity to gain valuable information concerning the geological succession in this northern part of South Dobrogea, with special regard to the carbonate formations hosting the aquifer. The boreholes were drilled to a depth of 700 m, for the identification and exploitation of aquifer horizons, in order to provide a fresh water supply for the NPP units. Geological analyses on drill cuttings and cores and geophysical well logging were carried out, for a comprehensive characterization of the intercepted formations from a lithologic and stratigraphic viewpoint, the identification of fractures/fissures and caverns as potential water-producing zones and the evaluation of formation porosity. The geophysical logs interpretation showed that the most probable water-producing zones are located in the so-called Dolomitic Complex (Kimmeridgian–Tithonian) on the 620–700 m (particularly 650–700 m) depth interval, in carbonates with average porosities of 12–16% and locally reaching more than 40%.

Carbonate reservoir is one of the most complex and important reservoirs in the world. It was confirmed that the slip-strike fault played a crucial role in the fault-dominated carbonate reservoir in Tarim basin. It is challenging to evaluate this kind of reservoir using the open-hole log or seismic data. Identifying and characterizing the fault-dominated carbonate reservoir were the objectives of this case study. High-definition borehole resistivity image and dipole sonic logs were run in several wells in the research area. It was revealed the detail features of the fault-dominated carbonate reservoir, such as natural fractures, faults or breccias. Compared with the typical geological model of strike-slip faults and outcrop features, the characteristics of the breccia zone and the fracture zone in the strike-slip fault system were summarized from the borehole image interpretation. A unique workflow was innovated with the integration of image and sonic data. Breccias and fractures were observed in the borehole image; and reflections or attenuations in Stoneley waveforms can provide indicating flag for permeable zones. Integrated with the other related geological data like mud logging or cores, the best pay zones in the fault-dominated carbonate reservoir were located. The characteristics of the strike-slip fault was revealed with the integration of the full-bore formation microimager and dipole shear sonic imager data. The fault core was a typical breccia zone with strong dissolution, which showed good potential in permeability, but it was found that some fault cores were filled with siliceous rock or intrusive rock. The features of the fillings in the fault zone were described based on the image and sonic data. The side cores or geochemical spectroscopy logs data helped to determine the mineralogy of the fillings. The fracture zones had clear responses in the image and sonic data too. The un-filled or half-filled breccia zone were the best zones in the fault-dominated carbonated reservoir. The details of the fault-dominated carbonate reservoir could be used in the future three-dimensional geological modelling.

Dissolution along zones of preferential flow enhances anisotropy in geological media and increases its complexity. Many karst models tend to be descriptive and fail to predict localization and structure of karst systems. Conduit architecture is difficult to derive from borehole data, and it can be hardly mapped even with the advent of 3D seismic techniques. Therefore, analysis of the geometry of karst conduit systems remains elusive where direct access to karst conduits is not possible. The present study investigates the relationship between lithofacies, tectonics and karstification in the Neoproterozoic Salitre Formation, located in the central-eastern Brazil. This unit comprises several systems of caves including the Toca da Boa Vista and da Barriguda hypogenic caves, the largest in South America, and focus of this study. We focused on cave mapping and morphogenetic analysis, determination of petrophysical properties, thin-section description, micro-tomography, and isotopic analysis. The Salitre Fm, deposited in an epicontinental sea, comprises mud/wakestones, grainstones, microbial facies, and fine siliciclastic rocks. The caves comprise 3D mazes with a network/spongework pattern. Passages occur in several levels within ca. 60 m thick cave-forming section, limited at the top by lithofacies with low permeability and fractures. Cave development occurred in phreatic sluggish-flow environment with overall upwelling flow. It rose via cross-formational fractures and distributed laterally within the cave-forming section using geological heterogeneities to eventually discharge up through outlets breaching across the upper confining beds. Cave formations include an assemblage indicating a period of water table conditions. Sediment fill includes deposits of dolomitic sand originated from in situ weathering of cave walls and ceiling. Caves show no relationship with the surface. Our data indicate several events of porosity evolution, such as subaerial exposure, folds and fractures, hydrothermal events (exotic minerals assemblage), sulfuric acid dissolution, dissolution at the water table, condensation corrosion, and faults and fractures reactivation. The major enhancement of secondary porosity was due to hypogene speleogenesis. Hypogene karst process may have implications to carbonate reservoirs not only through porosity enhancement, but also through their influence on regional flow systems, cross-formational communication, and migration of hydrocarbons Reference Cited

Seismic diffractions may play an important role in seismic interpretation because they characterize geological objects that might not be visible for conventional seismic attribute analysis. Diffractivity may be caused by, and consequently may define, tectonic dislocations (faults and fractures), lithological variations, fluid saturation within rocks.
In this paper, we tie seismic diffractions extracted from vertical seismic profiling (VSP) data and borehole logging, from which we recognize the reasons that are responsible for diffractivity of the strata. First, we process a multi-source multicomponent VSP data set to extract seismic diffractions and construct diffraction images of the strata for all three of the VSP data components. Then, we perform joint analysis of well logs and diffractions to obtain petrophysical attributes associated with diffraction images. We divide the rock succession into several units, which have different diffraction properties. We identify compacted rock, alternating intervals, isolated fractured zones, and fluid-saturated layers.

Preview Copulas are a new way of modeling the correlation structure between variables. Over the past forty years copulas have played an important role in several areas of statistics. But, only recently copulas have become popular in simulation models. Copulas are

The North Kuwait Jurassic Complex (NKJC) consists of six green fields with four identified reservoirs in the naturally fractured Jurassic carbonate formation. An integrated model has been constructed by incorporating seismic, geological, petrophysical, and engineering data to estimate the hydrocarbon pore volumes and to provide multiscenario production forecasts under various assumptions. A discrete fracture network (DFN) model was also incorporated using image logs, core data, and volume curvature attributes. The DFN model is further upscaled into a dual-porosity dynamic simulation model. Fracture characterization in the dynamic model requires translating the DFN attributes into three-directional permeability, aperture, and matrix-fracture transfer functions. Because of the inherent uncertainty of the fracture properties (fracture length, aperture, permeability, intensity, and connectivity) and the uncertainty involved in translating the "forest" of fractures into a dual-porosity model, calibration of the resulting model with well test and production data is essential to ensuring a dynamic model with acceptable predictive capabilities. There is a higher degree of uncertainty in the fracture geometry than in the matrix properties in the NKJC. This led to the decision to modify the fracture properties rather than the matrix properties for the purpose of calibrating/history matching the dynamic model. The following data was used for the purpose of calibrating the fracture network model: • Short-duration production tests from 31 wells • Long-term production data (48 months) from a testing facility (9 wells) • Sixteen pressure transient datasets (drawdown + buildup) from 12 wells • Eight months of production history from 20 wells Introduction The NKJC consists of six green fields extending over an area of 1772 km 2 with four major reservoir stratigraphic units: Najmah/Sargelu, Upper, Middle, and Lower Marrat. These units are separated by major flooding surfaces with persistent shale barriers, which prevent vertical communication among the three reservoirs. These reservoir stacks are composed of very tight fractured limestone and dolomites embedded with anhydrates and shales of Jurassic age.

Atmospheric carbon dioxide concentrations and climate are regulated on geological timescales by the balance between carbon input from volcanic and metamorphic outgassing and its removal by weathering feedbacks; these feedbacks involve the erosion of silicate rocks and organic-carbon-bearing rocks. The integrated effect of these processes is reflected in the calcium carbonate compensation depth, which is the oceanic depth at which calcium carbonate is dissolved. Here we present a carbonate accumulation record that covers the past 53 million years from a depth transect in the equatorial Pacific Ocean. The carbonate compensation depth tracks long-term ocean cooling, deepening from 3.0–3.5 kilometres during the early Cenozoic (approximately 55 million years ago) to 4.6 kilometres at present, consistent with an overall Cenozoic increase in weathering. We find large superimposed fluctuations in carbonate compensation depth during the middle and late Eocene. Using Earth system models, we i...

Upper Jurassic carbonates of the Mozduran Formation constitute the principal reservoir intervals
at the giant Khangiran and Gonbadli gasfields in the Kopet Dagh Basin, NE Iran. These carbonates
were investigated using detailed field studies and petrographic and wireline log analyses in order
to clarify their depositional facies and sequence stratigraphy. Facies were interpreted to reflect
deep basin, fore-shoal, shelf margin, lagoon, tidal flat and coastal plain depositional systems.
The Mozduran Formation is composed of six depositional sequences. Thickness variations
were controlled by differential subsidence. Aggradation on the platform margin and reduced
carbonate production in the deep basin together with differential subsidence resulted in the creation
of a narrow seaway during the late Oxfordian. Petrographic studies suggest that Mozduran Formation
carbonates had a low-Mg calcite mineralogy during the Oxfordian, and an aragonite to high-Mg
calcite mineralogy during the Kimmeridgian. Reservoir pay zones are located in highstand systems
tracts within the lower and middle Kimmeridgian depositional sequences. The rapid lateral thickness
variations of these sequences were controlled by tectonic factors, leading to compartmentalization
of the Mozduran Formation reservoir with the possible creation of stratigraphic traps, especially at
the Khangiran field.

Two 3D ground-penetrating radar (GPR) surveys collected on northwest Andros Island, Bahamas, facilitate understanding the architecture and evolution of carbonate sedimentary environments that are often unseen in 2D outcrop and core. A 200-MHz 3D GPR dataset was collected over Late Pleistocene (isotope stage 5e) bedrock at a schoolyard in northwest Andros over an area of 61 m x 61 m. This survey reveals a ~18-m wide oolitic barform that trends southwest-northeast through the study area with foresets dipping to the northwest and a ~12-m-wide tidal channel that trends north-northwest through the northeast part of the survey. These two prominent features are surrounded and underlain by low-energy mud deposits. A deeper radar surface can be seen at ~6.4 m depth dipping gently to the west, and is interpreted to be a sequence boundary. In order to better resolve the lateral and vertical spatial interaction between the shallower features (<3.5 m), a higher resolution, 35.8 m x 29.6 m 400-MHz 3D GPR dataset was collected with the survey direction optimized to image the barform and its foresets (i.e., the profiles were collected in the direction of dip). The interpretation of these features is enhanced by modern analogs found nearby at Joulters Cays, and by three cores and 56 thin sections collected through the crest and toe of the barform, and through the channel feature. The integration of geophysical and geological data enables the recognition and reconstruction of a Pleistocene depositional environment and its associated fine-scale process sedimentology, including changing current directions, barform accumulation patterns and non-depositional and erosional events.

ABSTRACT Integrated facies and diagenetic analyses within a sequence stratigraphic framework were carried out on mid- Cretaceous Sarvak carbonate reservoirs in five giant and supergiant oilfields in the central and southern parts of the Dezful Embayment, SW Iran. Results of facies analysis indicate a homoclinal ramp-type carbonate platform for this formation with the frequencies of different facies associations in six wells reflecting their approximate position in the sedimentary model. Diagenetic studies indicate periods of subaerial exposure with different intensities and durations in the upper Sarvak carbonates producing karstified profiles, dissolution-collapse breccias, and thick bauxitic-lateritic horizons. Sequence stratigraphic interpretations show that the tectonic evolution of the NE margin of the Arabian Plate (Zagros Basin) during Cenomanian– Turonian times shaped the facies characteristics, diagenetic features, and strongly influenced reservoir formation. Reactivation of basement-block faults and halokinetic movements (related to the Hormoz salt series) in the middle Cretaceous, resulted in the development of several paleohighs and troughs in the Dezful Embayment hydrocarbon province. Movements on these structures generated two and locally three disconformities in the upper parts of Sarvak Formation in this region. The paleohighs played an important role in reservoir evolution within the Sarvak Formation in three giant-supergiant oilfields (including Gachsaran, Rag-e-Safid, and Abteymour oilfields) but where these structures are absent reservoir quality is low.

Kuwait Oil Company (KOC) is engaged in an early phase of development of a giant, tight, fractured carbonate play within the State of Kuwait, spread over a large area covering six fields. The producing reservoirs belong to the geological Formations of Toarcian to Tithonian age. Some reservoirs are characterized by very low porosity and permeability and productivity of these reservoirs is driven by the natural fracture system. This paper described the approach followed in developing a 3D fracture model for these reservoirs. Carefully planned data acquisition resulted in a rich suite of dataset consisting of image logs, conventional cores covering the target pay zones in a number of wells. Analysis of these data gave a clear understanding about fracture orientation, density, aperture, and other fracture parameters. Special 3D seismic processing was carried out to derive a volume curvature attribute, which was able to detect and identify the fracture corridors away from the wells. Structural geological analysis resulted in an understanding of the tectonic history of the area, which helped in genetically relating the identified fracture orientations with the structural evolution. A discrete fracture network was developed for these reservoirs combining the well and seismic attribute data. Parameters like aspect ratio, orientation and aperture of fractures was assigned to different fracture sets based on this analysis. The apertures were corrected for the present day stress effect based on the borehole breakout data. This fracture model was upscaled into the 3D geological model to get the fracture porosity and the permeability tensors. The fracture model was validated by history matching pressure build up and production data and was used for dynamic flow simulation studies for the field development planning.

Abstract This paper discusses the planning process, execution and lessons learned of an advanced horizontal water injector in a tight carbonate reservoir, onshore United Arab Emirates. The well design required a 10,000 ft horizontal section, to be geosteered in a 6⅛ ...

Under-Balance Drilling (UBD) has been used in several carbonate fields of the Cluster, North Oman at Petroleum Development Oman (PDO). The reasons have been to improve productivity and injectivity, real-time reservoir characterization and to reduce/eliminate acid clean out. By using UBD in several fields, a better picture of well candidate selection and benefits has been derived.

Geochemical composition of carbonate sediments are in
equilibrium
with
the
contemporaneous
sea
-
water composition in absence of considerable
biotic
fractionation
. However, in carbonate sediments, diagenetic
im
prints
may
have considera
ble effects on primary sediments textures, mineralogy,
reservoir quality and finally geochemical characters. Depending on some
factors including primary (depositional) sediments characteristics,
governing climate and diagenetic history,
geochemical composi
tion of
carbonates has been altered by post
-
depositional overprints. Stable
isotopes and trace elements analyses can be used as a good tool to
measure
the extent
of these
alterations
1
,
2
. Coupled imprints of tropical climate and
recurring emersions ha
d
cons
iderable effects on Middle
-
Upper Cretaceous
carbonate reservoirs of the SW Iran (Dezful
E
mbayment) and Middle East
region
3
.
Petrographic studies (
from
core to thin section scales) and
geochemical analyses (stable isotopes and trace elements) were carried out
on 478 samples from
fi
v
e giant and supergiant oilfields in
these
e
mbayment
to reveal the main diagenetic alterations of these
karstified
carbonate
sequences
(Fig. 1)
.
Variations in
δ
18
O and
δ
13
C
compositions
and
trace
elements
(
Mn, Fe and Sr
)
concentrations
are useful diagenetic
indicators
that
resulted in
classification of
studied intervals
into
four
diagenetic
classes
according to their
meteoric diagenetic features,
intensities and developments.