Carbonate reservoirs are complex and require care in choosing an appropriate velocity model (
In this paper, three core-derived velocity models, developed as part of the earlier study (
Our findings are summarized as follows: (1) Model A, velocity as a function of porosity, is less sensitive to changes in rock stiffness and thus, is more reliable than Model B, (2) Model C, which predicts shear velocity, shows an overall better estimation of shear velocity than publicly available carbonate models from
The ALBION project applies a new and disruptive methodology of reservoir characterisation to the carbonate Urgonian Formation (South-East France) considered as the very best analogue of Mid Cretaceous reservoirs from Middle East. Thanks to numerous field sections and outcrops descriptions, to tens of wells drilled in the reservoir, to kilometres of cores, to monitoring of groundwater dynamics such as decades of hydraulic observations at pretty much the only natural outlet of a major groundwater reservoir (Fontaine-de-Vaucluse spring) and to a unique underground laboratory (LSBB, about four kilometers in the heart of the reservoir), a multi-scale model is being built for reservoir purpose. Different observation sites with wells whose spacing ranges from 2 to 20 meters contribute to the assessment of together the matrix, the fractures and the karst flow behaviours. Through the building of an observatory in the heart of a reservoir, the ALBION project is delivering advanced concepts and methodologies to apply to industrial projects in Middle East carbonate fields.
Zimmermann, Udo (University of Stavanger, The National IOR Centre of Norway) | Madland, Merete. V. (University of Stavanger, The National IOR Centre of Norway) | Minde, Mona (University of Stavanger, The National IOR Centre of Norway) | Borromeo, Laura (University of Stavanger, The National IOR Centre of Norway) | Egeland, Nina (University of Stavanger, The National IOR Centre of Norway)
Samples of chalk are flooded with different brines to observe the reactivity of the material with determining and quantifying the mineralogical changes. The type of chalk, the composition of the fluid and the pressure and temperature conditions are varied to understand how these parameters impact fluid flow and compaction which surely is an important drive mechanism for enhanced oil recovery (EOR). Changes in mineralogy affect porosity and permeability and controls compaction of a rock. This compaction is, in itself, an important drive for increased production of oil and the rock-fluid interaction is also believed to have a positive effect on altering the wettability of the rock towards more water-wet. We chose on-shore chalk (from Belgium, Denmark, USA) to compare results with reservoir chalk and to prepare pilot studies in chalk reservoirs and a homogenized, artificial core of 99.95% CaCO3-powder with micron-like grain sizes. The use of MgCl2 brines injected under reservoir conditions (130°C; 10-14 MPa effective stress) into drilled chalk plugs (diameter: 3,8cm; length: 7cm) produced significant effects in terms of mineralogical changes in chalk, which are studied by optical petrography, X-ray diffraction, whole-rock geochemistry, C-O isotope geochemistry, Mineral Liberation Analyzer (MLA), conventional scanning electron microscopy coupled with energy dispersive systems (SEM-EDS) methodology, electron microprobe analysis, nano-secondary ion mass spectrometry, micro-Raman and tip enhanced Raman spectroscopy coupled with atomic force microscopy and transmission electron microscopy (TEM). Tests have been carried out from weeks to a length of three years. Generally, we observe a mineralogical change from calcite to magnesite. Processes of dissolution, precipitation and re-precipitation are beyond doubt recognised. Mineral growth takes place after a short time of flooding with nano-scale Mg-rich carbonates, mostly as magnesite. Crystal boundaries between magnesite and calcite are sharp even on nano-scale (TEM). MLA shows that the mineralogical changes take place in two stages, one causes a mixture of Mg-rich carbonates (or magnesite) and calcite, while a second stage changes gradually the entire sample to nearly pure magnesite. Whole-rock geochemistry, TEM-EDS show that still c. 4wt.% of CaO is left in the altered chalk even after three years testing. MLA showed that the type of paleontological material alters in different velocities from calcite to Mg-rich carbonate (respectively magnesite) and that fossil debris hampers fluid flow. The observed mineralogical changes have a significant effect on porosity calculations, which implies that estimations of porosity in chalk without taking mineralogical changes into account are misleading. Results also showed that micro-Raman spectroscopy is capable of estimating MgO concentration in carbonates and identifying new grown mineral phases in a very quick, non-destructive, cheap, and effective way and that c. 4wt.% of CaO is left in the entirely altered chalk after three years of flooding.
OMV and ADNOC signed a study agreement in 2013 to explore for hydrocarbons in a large (10,000km2) under-explored onshore area, named East Abu Dhabi. The objective of the work programme was to evaluate the conventional and unconventional hydrocarbon potential within multiple play types and structural settings, via the analysis of existing vintage data, acquisition of new seismic followed by exploration drilling.
To date 1,800km2 3D (4S) and 700km 2D seismic have been acquired focused on two principal play types; namely, the ‘Pabdeh’ stratigraphic play and the ‘Thamama’ combined structural/stratigraphic play. Additional studies completed include fluid inclusion stratigraphy using data from nearby vintage wells, and the completion of an unconventional study covering the wider area of interest. The first OMV operated exploration well reached its TD in the Jurassic in March 2017. Two tests have been performed in Lower Cretaceous and Jurassic resulting in a dry sour gas discovery.
The main results of the well that have an impact on the understanding of the regional geology can be summarized as follows: 1) Source Rock, three potential source rock intervals have been penetrated (Middle and Lower Cretaceous & Jurassic). 2) Reservoir, The middle Cretaceous has been found in a back-shoal facies with its suggested corresponding platform margin being located in close proximity to the South-West. The Aptian is represented by the classical Lower Shuaiba fm. and overlain by the Bab shales. No isolated platform has been encountered. 3) Clear stratigraphic and structural evidence supporting structural deformation of the Thamama Group during the Lower Cretaceous. Several distinct fault trends are evidenced from both the well data and 3D seismic depth slices. Understanding these faults and related fracture systems will be fundamental in understanding the play potential in the wider area.
This is the first exploration well to be drilled in the area since the ‘80s. Multiple intervals of regional interest have been encountered spanning the massive loss circulation intervals of the Palaeocene, conventional and unconventional reservoir within the Middle Cretaceous, the entire Lower Cretaceous sequence and the Asab equivalents of the Upper Jurassic.
With the increase of Egypt's domestic demand for energy, economical production from unconventional reservoirs is a great challenge to maintain production's annual decline. This has spurred interest in the development of unconventional resources, such as tight reservoirs and shale gas, particularly because of the enormous success in North America that brought unconventional resources to the forefront of the discussion on the future of energy. The country has launched studies to evaluate, explore and appraise several prospects for unconventional gas in Shoushan-Matrouh and Abu Gharadig basins. Exploratory pilot data wells were drilled and completed in the appraisal program for collecting the required data to evaluate the reservoirs qualities, demonstrate the availability of reserves, and identify optimal technology to maximize productivity and set the foundation for future development of these unconventional plays. Logs, core testing, and analysis service data were performed on or collected from these wells. Laboratory testing was conducted to understand the complex mineralogy and variable rock fabric. Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple-combo full-wave sonic logs and core samples were combined to develop sophisticated models. These understandings helped reduce uncertainty and the lessons learned from this work and presented in this paper helped define completion and stimulation technologies for horizontal wells.
This objective of this paper is to review of the results and share lessons learned related to the recent appraising activities of unconventional plays in Egypt's western desert, evaluate these unconventional resources to unlock their potential. In addition, this paper present the challenges of development, highlight the best strategies required for field development to capitalize on the promising potential of these reservoirs through an integrated advanced workflow. The results from this study will shed light on the results of recent unconventional gas exploration and appraisal activities, which indicate that the western desert of Egypt holds substantial resources of unconventional gas. This unconventional gas can help to change the slope of production rates in the country positively and set the foundation for future development of these plays.
The Wasia Formation presents opportunities to explore for stratigraphic traps in the Saudi Arabian Rub’ Al-Khali Basin because it contains numerous interbedded reservoirs, sources, and sealing rocks. The mid-Cretaceous Wasia Formation includes a rudist carbonate platform with five, third-order sequences comprising, from oldest to youngest, Safaniya, Mauddud, Ahmadi, Rumaila, and Mishrif members. These members include proximal shallow-marine, highstand carbonate shoals at the platform margin in close proximity to fine-grained carbonate deposits in the Shilaf Basin. The resulting depositional cycles and stratigraphic architecture position muddy-tight seals, adjacent to porous shallow-marine carbonate-shoal bodies. Two members (Safaniya and lowermost Mishrif) have high organic-matter content situated in the oil window.
Core data, well logs, seismic signals, and modern analogs were analyzed to help understand the Wasia deposition. Detailed correlations were made of well logs and neural network training was used to generate electro-facies. Next, supervised waveform analysis was used, correlated to five well log facies, to create five waveform facies including (1) lagoon, (2) back-shoal, (3) shoal, (4) slope, and, (5) basin facies. Sources of potential uncertainties include data processing, seismic to well ties, position of stratigraphic tops and seismic horizon interpretation. To minimize these, care was taken in data processing and a blind test was performed to validate the final interpretation.
On the basis of integrating the aforementioned data with our waveform facies, a reference geological model was built demonstrating that potential stratigraphic traps are porous, shallow-marine carbonate shoals intercalated with muddy-tight slope deposits resulting in isolated, porous carbonate reservoir bodies sealed by tight rocks. For example, the Ahmadi Memberseal was deemed to be too thin to seal the oil in the underlying Mauddud. In addition, muddy-tight lowermost Mishrif Member strata are also too thin to seal oil in the underlying Rumaila. In the worst case, laterally extensive upper Mishrif reservoirs are not sealed by interbedded lateral seals even though the Aruma shale seals their tops. The two best trap configurations include (1) the first highstand lower sequence of the Mishrif reservoir sealed by interbedded extensive transgressive muddy Mishrif carbonates and (2) thick Ahmadi and lowermost Mishrif fine-grained carbonates sealing Mauddud and Rumaila highstand system tracts.
Specifically selected and manufactured organic fibres were used to bridge microfractures and stabilize shale and mudstone formations while drilling the Fiqa, Shilaif, Mishrif, Maddud and Nahr Umr formations and during a 5-day logging interval at the Mishrif formation.
A newly developed method for testing invasion depth in 20/40 gravel pack sand, in order to monitor the fluids' bridging capability, was developed for drilling and logging the unstable Middle Cretaceous formations. The information from the tests was actively used to monitor and maintain the concentration of organic fibre materials in the drilling fluid to reduce invasion and to stabilise the highly fractured and layered shale and mudstone. A treatment programme was established around the data collected, using drilling fluids from the active system with a high concentration of fibres which was streamed back into the active system accordingly. The depletion rate was recorded and compared with the various formations during drilling.
The drilling fluid chosen for the project was a water-based system, with 14% NaCl to balance
The hard and brittle shales found in this group of formations have been problematic for drilling in the Arabian Peninsula for a long time. The Nahr Umr formation is particularly known for its loose structure and frequent hole collapses which are caused by fluid penetration along pre-existing fractures and laminated surfaces. Oil-based drilling fluids are the preferred systems of choice to reduce the capillary effect of invading fluids, and the consensus is to reduce the exposure time for the formations as much as possible.
As a water-based drilling fluid was chosen, a program was set up to focus primarily on a rapid build-up of a filter cake to bridge fractures and reduce filtrate invasion. The chosen organic fibres are anionic in nature and therefore have an affinity to the broken edges of clay platelets with a proven ability to create a network with particles that bridge the formation.
The 12 ¼" section was drilled without stability issues and without remedial back reaming to the logging depth. The top part of the 12 ¼" section was kept open for 5 days during logging. The Nahr Umr formation was drilled with a controlled, low ROP to identify the setting depth for the 9 5/8" casing in top Shuaiba formation. Total open hole time was 4 days after logging.
The casing was cemented without losses or other operational issues.
The use of specific organic fibres to stabilise highly fractured shale formations presents a low cost and efficient method for dealing with a high-cost problem associated with significant NPT.
Real time data collection and close monitoring of the fluids bridging capability using a fluid-invasion test kit proved to be an effective method for responding quickly to changes in hole stability, formation strength/integrity and fluid invasion.
Identification of hydrocarbon generating source rocks and evaluation of their potential are essential in the exploration and development of hydrocarbon resources. For an offshore oil field in Abu Dhabi, we conducted geochemical study using crude oil and core samples from Upper Cretaceous Cenomanian carbonate rocks. The study objectives are 1) correlation of crude oil and source rock with biomarker, and 2) evaluation of the source rock potential.
The Cenomanian carbonate rocks of the oil field are composed of shallow marine porous limestone and deep marine lime mudstone. This Cenomanian lime mudstone was believed as source rock of the crude oil in the interfingered Cenomanian porous limestone reservoirs. However, the origin of crude oil has been poorly constrained with geochemistry yet. In this study, we carried out geological description and RockEval pyrolysis analysis of core samples to evaluate source rock potential of the lime mudstone. Then, biomarkers such as hopane, sterane and compound specific isotopic ratio of n-alkane were analyzed to correlate the source rock and the crude oil samples with GC/MS, GC/MS/MS and GC/C/IRMS for high resolution biomarker measurements and robust interpretation.
As a result, the biomarker fingerprints of the crude oil in porous limestone and the organic material in the lime mudstone show significant similarity. It proves that the crude oil in the porous limestone is migrated from interfingered organic rich Cenomanian lime mudstone. In addition, the lime mudstone shows excellent source rock property (Total Organic Carbon exceeding 4%, Hydrogen Index > 600mg/g TOC) and categorized as Type I/II source rock deposited in marine environment. Furthermore, the biomarkers effectively constrain the maturity of source rock which is difficult to evaluate with Vitrinite Reflectance and RockEVAL analysis. Consequently, the timing of hydrocarbon generation and the area of effective source rock will be interpreted based on our study result with higher confidence.
This study deepens understanding of Cenomanian petroleum system in offshore Abu Dhabi. The result suggests the advantage of biomarker application not only in oil-source correlation but also in source rock maturity analysis.
Kohda, Atsuro (INPEX Corporation) | Bellah, Sameer (ZADCO) | Shibasaki, Toshiaki (ZADCO) | Farhan, Zahra Al (ZADCO) | Shibayama, Akira (INPEX Corporation) | Hamami, Mohamed Al (ZADCO) | Jasmi, Sami Al (ZADCO)
The understanding of heterogeneous rock properties especially high-permeability streaks is very important to predict fluid behavior in carbonate reservoirs. An Upper Jurassic reservoir in "Field A" has been producing for 30 years with different production scheme such as crestal water and gas injection at the different stage. The observed water/gas breakthrough and the evolution trend in water cut/GOR indicate reservoir heterogeneity caused by geological complexity. To replicate such complicated fluids behavior in reservoir model, the characterization study for high-permeability streaks was conducted.
Multiple data sources were used to identify and characterize high-permeability streaks.
Interpreted injected gas/water sweep intervals utilizing cased-hole production logging. Identified potential high-permeable lithofacies and its stratigraphic positions by detailed core and thin section descriptions with petrophysical observations. Defined high-permeability streaks based on the integrated interpretation of multiple data sources. Characterized the high-permeability streaks in reservoir model with excess flow capacity estimated from model and well-test permeability.
Interpreted injected gas/water sweep intervals utilizing cased-hole production logging.
Identified potential high-permeable lithofacies and its stratigraphic positions by detailed core and thin section descriptions with petrophysical observations.
Defined high-permeability streaks based on the integrated interpretation of multiple data sources.
Characterized the high-permeability streaks in reservoir model with excess flow capacity estimated from model and well-test permeability.
This study revealed that multiple types of high-permeability streaks present in the reservoir. In particular, it was recognized that a specific thin layer comprises stromatoporoid (epibenthic calcified sponges) patch reef deposits acts as the main contributor for fluids movement. This paper shows how to characterize the high-permeability streaks in reservoir model focusing on stromatoporoid lithofacies.
Thickness of stromatoporoid lithofacies shows heterogeneous variation of 0 to 14 feet. The complex pore system in stromatoporoid lithofacies associated with heterogeneously distributed skeletal fragments with centimeter-scale makes difficulty for capturing accurate permeability from conventional plug measurement. The plug permeability was generally underestimated comparing with actual flow capacity estimated from well-test. Hence the modeled permeability which generated from porosity-permeability correlation coming from plug measurement was required further conditioning based on the pre-established concept for high-permeability streaks.
To fill the gap between modelled and well-test permeability-thickness (KH) i.e. excess KH, the relevance between excess KH and stromatoporoid lithofacies was investigated. As a result, it was found that the zonal well-test KH increases as stromatoporoid lithofacies thickness (STR-H) increases, and there is a good correlation between STR-H and STR-KH estimated as "zonal well-test KH" minus "zonal modeled KH except stromatoporoid lithofacies intervals". Therefore, excess KH was allocated to only into the part of stromatoporoid lithofacies. The prepared STR-H map was directory transformed to STR-KH distributions by the revealed correlation. Through dynamic history matching, permeability distribution was iteratively modified by updating STR-H map in concordance with depositional concept.
Detailed observations and integrated interpretation for multiple data sources allowed identifying high-permeability streaks and establishment of a model workflow for representing its heterogeneity and associated permeability distribution. This workflow enabled geologically reasonable permeability conditioning and iterative model update in conjunction with the depositional concept during dynamic history matching.
Hu, Jialiang (Abu Dhabi National Oil Company) | Al Blooshi, Abdulla (Abu Dhabi National Oil Company) | Mavromatidis, Angelos (Abu Dhabi National Oil Company) | Witte, Joop (Abu Dhabi National Oil Company) | Neves, Fernando (Abu Dhabi National Oil Company) | Caeiro, Maria Da Silva (Abu Dhabi National Oil Company)
According to the drilling results in Abu Dhabi, the sweet-gas prospective of the Silurian-Permian pre-Khuff clastics is risked by the reservoir uncertainty controlled by different types of clastics. Previous studies focused on well-scale deposition analysis barely reflects the regional sedimentary geometry nor predicts the distribution of different sand-bodies in the pre-Khuff sequences. To better map the play-fairway and to mitigate the drilling uncertainty, it is of significant importance to model the regional depositional settings with different reservoir sands based on the integrated sediment study.
The regional sequence framework was based on the biostratigraphy study and log cycles. To model the original deposition, eroded sequences and re-worked sediments were re-constructed based on the near offset data. The plate-scale depositional model was integrated with Abu Dhabi sedimentary records based on cores, cutting description and log interpretation to create a statistics database of depositional settings in each sequence. Training images that accommodate the changes in sedimentary records were created adapting seismic patterns and subsequently were used for the multi-point statistics and object modeling.
After the Silurian marine-delta deposition, the continuous non-deposition in southern onshore area and the intermittent erosion in offshore due to periodic salt movement suggests a successive deepening of the paleo-relief to northern Abu Dhabi. The sea-level drop since Silurian creates the marine to continent transition and results in the prograding of continent sediments to the north following the relief of the Paleozoic salt withdraw basin. The Devonian dolomite-anhydrite sediments indicate the extension of marine carbonate from Saudi, Iraq and Kuwait to northwest offshore Abu Dhabi. After the Carboniferous glaciation, the terrigenous sediments become dominant in Berwath, Unayzah and Basal Khuff Clastics. The south and east of Abu Dhabi is pre-dominantly fluvial original, while the west area records both fluvial and Aeolian deposition. The widespread of Aeolian sands is compromised by the flooding events of fluvial and sheet-flow. The mud coated fluvial sands can preserve fairly better permeability than the well-sorted Aeolian sands due to the inhibition to quartz cements, which makes it also primary reservoir target. The Western and central offshore areas at the transition of Aeolian-fluvial sands and floodplain muds are more favorable for the development of reservoir and seal interlayering.
Rather than assigning one dominant facies to each pre-Khuff formation as the previous work, the regional stochastic model differentiates fluvial channels, crevasse splays, aeolian dunes, sheet-flood and marginal marine/lacustrine deposits in each sequence based on solid well data and regional statistics. Therefore, improve the understanding of the stacking patterns of reservoirs and seals that can be used to characterize the pre-Khuff hydrocarbon behavior, integrating studies of structure growth, burial and maturation history.