Lower Cretaceous Carbonate Reservoir Research Articles

The role of stylolites as a fluid conductive, in the heterogeneous carbonate reservoirs

Stylolites possess a dual function in assessing the quality of the Lower Cretaceous carbonate reservoir in the Abadan Plain, Zagros Basin. They can either operate as barriers or facilitate the flow of fluids. To investigate this, we conducted a comprehensive study using core-plug samples, thin section petrography, high-resolution computed tomography, geochemical analysis, and petrophysical evaluation. Our findings indicate that stylolite surfaces can enhance effective porosity and connectivity by acting as open pathways. In the Fahliyan Formation, stylolites can be classified into four types based on their characteristics, including shape, size, amplitude, and the presence of insoluble material in the seams. The genetic type of stylolites is determined by the dominant stress direction, while various parameters in the burial diagenetic stage, such as pressure, temperature, and the presence of soluble ion-rich fluids, can affect porosity and permeability. Stylolites in the Fahliyan facies create continuous and connected porosity for fluid flow, with their amplitude and morphology impacting reservoir quality, especially in mud-supported facies. Therefore, the presence of stylolites in mud-supported facies can improve porosity and permeability. Dissolution, reduced overburden pressure, and horizontal compression are the main factors that expose the stylolite surfaces in the Fahliyan Formation. The extent of cementation, which is the primary barrier feature, varies significantly across the Fahliyan Reservoir in the Abadan Plain Zone due to the degree of stylolitization in the examined facies. However, our findings from wells and geological data combination indicate that reservoir quality in the examined formation facies is significantly influenced by various conditions, with a particular emphasis on the type of fluid flow in the passages.

Experimental and digital investigations of heterogeneity in lower cretaceous carbonate reservoir using fractal and multifractal concepts

Characterization and prediction of reservoir heterogeneity are crucial for hydrocarbon production. This study applies the multifractal theory using both numerical and experimental data to characterize quantitatively the heterogeneity of pore structures in Lower Cretaceous limestone reservoir from the United Arab Emirates. Fractal dimensions calculated from three dimensional digital images showed good correlation (R2 = + 0.69) with experimental high-pressure mercury injection (HPMI) measurements. Moreover, both experimental and numerical fractal dimensions correlate well with experimental HPMI porosity measurements. Multifractal parameters such as the non-uniformity degree of the pore structures Δα, the asymmetry degree in the vertical axis Δf(α), the concentration of pore size distribution α0 and the asymmetry degree in the horizontal axis Rd estimated from digital and experimental data correlated well and revealed ability to quantitatively describe samples heterogeneity. The ranges of digital and experimental multifractal parameters provided the means to differentiate between homogeneous and heterogeneous samples.

Dolomitization of the lower cretaceous carbonate reservoir in the Euphrates Graben, Syria

Results of this study are based on core materials description, thin sections, Cathodoluminescence (CL), and Scanning Electron Microscope (SEM) examinations. The Lower Cretaceous over the Euphrates Graben area was characterized by carbonate sedimentation in shallow marine environments. The low energy lagoonal to inner shelf sediments of the Judea Formation includes micritic mudstone to wackestone texture, dolomitic limestones and dolostones. Two types of dolomites recognized in the carbonates of the Judea Formation, the preserving microcrystalline dolomites which commonly founded in the partially dolomitized micritic limestones, and the destructive coarsely crystalline dolomites which commonly founded in the dolostones and dolomitic limestones. Petrographic examinations indicate that the preserving microcrystalline dolomites represent subtidal cycles developed in a shoal to open marine depositional environments, they probably formed under conditions of the shallow burial diagenesis. The destructive coarsely crystalline dolomites may develop in more basinward, open marine environments under conditions of the deep burial diagenesis that accompanied by rising in temperature, pressure, and burial depth. It is believed that evolution of the diagenetic history of the Judean Formation sediments occurred in two diagenetic stages; the shallow burial diagenesis, and the deep burial diagenesis. Compaction processes, early fracturing, micritization, early calcite, and the early phase of dolomitization were part of the multiple diagenetic alterations during the shallow burial diagenesis. The deep burial diagenesis was marked by dissolution, late stage of dolomitization and replacement, mechanical and chemical compaction, and the late calcite precipitation. It is believed that dolomitization of the Judea Formation carbonates in the Euphrates Graben has contributed to improving the reservoir properties by increasing the porosity and thus the permeability.

Origin and evolution of microporosity in packstones and grainstones in a Lower Cretaceous carbonate reservoir, United Arab Emirates

Abstract Microporosity in carbonate reservoirs is generated by the complex interplay between depositional and diagenetic processes. This petrographical, SEM, fluid-inclusion and isotopic study of a Lower Cretaceous carbonate reservoir, Abu Dhabi, UAE, revealed that: (1) micritization of ooids and skeletal fragments, which resulted in spheroidal (rounded) micrite, accounts for most microporosity in peloidal packstones and grainstones; and (2) transformation of spheroidal micrite into subhedral/euhedral micrite and microspar, known as aggrading neomorphism, could happen via precipitation of syntaxial calcite overgrowths around micrite (micro-overgrowths) and not only, as suggested previously in the literature, by recrystallization involving the dissolution (of micrite) and reprecipitation (of microspar). Precipitation of calcite cement around micrite (i.e. destruction of microporosity) is more extensive in the water zone than in the oil zone, which is possibly contributing to the lower porosity and permeability of the carbonate reservoir in the water zone. Similarity in bulk oxygen isotopic values of micritized packstones and grainstones in the water and oil zones (average δ 18 O V-PDB = −7.2‰ and −7.8‰, respectively) is attributed to: (1) a small difference in temperatures between the crest (oil zone) and the flanks (water zone); and (2) calcite precipitation around micrite occurred prior and subsequent to oil emplacement. Bulk carbon and strontium isotopic compositions of micritized packstones and grainstones in the water and oil zones (average δ 13 C V-PDB = +3.7‰ and average 87 Sr/ 86 Sr ratios = 0.707469) indicate that calcite cement was derived from marine porewaters and/or dissolution of the host limestones. The minimum formation temperatures of bulk micrite/microspar, which are inferred based on paragenetic relationships, fluid-inclusion microthermometry and oxygen isotope data, are around 58–78°C.

Impact of stylolitization on diagenesis of a Lower Cretaceous carbonate reservoir from a giant oilfield, Abu Dhabi, United Arab Emirates

Bed-parallel stylolites are a widespread diagenetic feature in Lower Cretaceous limestone reservoirs, Abu Dhabi, United Arab Emirates (UAE). Diagenetic calcite, dolomite, kaolin and small amounts of pyrite, fluorite, anhydrite and sphalerite occur along and in the vicinity of the stylolites. Petrographic observations, negative δ18OVPDB, fluid inclusion microthermometry, and enrichment in 87Sr suggest that these cements have precipitated from hot basinal brines, which migrated along the stylolites and genetically related microfractures (tension gashes). Fluid migration was presumably related to lateral tectonic compression events related to the foreland basin formation. The low solubility of Al3+ in formation waters suggests that kaolin precipitation was linked to derivation of organic acids during organic matter maturation, probably in siliciclastic source rocks. The mass released from stylolitization was presumably re-precipitated as macro- and microcrystalline calcite cement in the host limestones. The flanks of the oilfield (water zone) display more frequent presence and higher amplitude of stylolites, lower porosity and permeability, higher homogenization temperatures and more radiogenic composition of carbonates compared to the crest (oil zone). This indicates that oil emplacement retards diagenesis. This study demonstrates that stylolitization plays a crucial role in fluid flow and diagenesis of carbonate reservoirs during basin evolution.

Permeability Prediction in Carbonate Reservoir Rock Using FZI

Knowledge of permeability, which is the ability of rocks to transmit the fluid, is important for understanding the flow mechanisms in oil and gas reservoirs.Permeability is best measured in the laboratory on cored rock taken from the reservoir. Coring is expensive and time-consuming in comparison to the electronic survey techniques most commonly used to gain information about permeability.Yamama formation was chosen, to predict the permeability by using FZI method. Yamama Formation is the main lower cretaceous carbonate reservoir in southern of Iraq. This formation is made up mainly of limestone. Yamama formation was deposited on a gradually rising basin floor. The digenesis of Yamama sediments is very important due to its direct relation to the porosity and permeability.In this study permeability has been predicated by using the Flow zone indicator methods.This method attempts to identify the flow zone indicator in un-cored wells using log records. Once the flow zone indicator is calculated from the core data, a relationship between this FZI value and the well logs can be obtained.

Microfacies and environmental study of the lower cretaceous yamama formation in Ratawi field

The Yamama Formation is the main Lower Cretaceous (late Berriasian–Valangenian) carbonate reservoir in southern Iraq. Petrographic study from thin-section examination shows that the skeletal grains included calcareous algae from both red and green algae. Red algae is concentrated in the upper part of the Formation, and the most important of this algae species is Permocalculus ssp. Green algae is less common, and its concentration is in the middle part of the Formation. The most species found in the Yamama Formation is dasycladeans, and both small and large species of benthonic foraminifera such as Nautiloculina, Textularia, Trocholina, Pseudocyclammina, and Everticyclammina are also present. The non-skeleton grains included oolites, pellets, and micrite. Six cyclic type microfacies have been recognized for Yamama Formation in Ratawi-3 (Rt-3) and Ratawi-4 (Rt-4) Wells, namely peloidal packstone–grainstone, algal wackestone–packstone, oolitic–peloidal grainstone, bioclastic wackestone–packstone, foraminiferal wackestone, and mudstone microfacies. The latter has been divided into two submicrofacies: argillaceous lime mudstone and fossiliferous lime mudstone. The lateral extension of these microfacies has been identified by integrating the thin-section data and well logs’ character variations with similar characteristic for microfacies. The Yamama Formation was affected by five diagenetic processes, which are micritization, cementation, recrystallization, silicification, and stylolites. The Yamama Formation was deposited during a regressive period within the outer ramp, shoal, and inner ramp setting.

Petroleum accumulation and leakage in a deeply buried carbonate reservoir, Níspero field (Mexico)

The filling history of the Níspero deeply buried Lower Cretaceous carbonate reservoir (below 4000 m) from the south part of Gulf of Mexico was studied using a combination of data from petrography, stable isotopes and fluid inclusions and compared with a one-dimensional burial model to derive timing. A combination of techniques such as microthermometry, confocal laser scanning microscopy (CLSM) and Raman microspectroscopy have been used to characterize the different fluid inclusion assemblages and discriminate between the reequilibrated and the preserved fluid inclusions. The Níspero reservoir is composed of a fractured finely crystalline replacement dolostone. A first generation of fractures is filled by a non-planar dolomite cement, and a second generation by a planar-E dolomite cement and a blocky sparite. The reservoir is lastly stylolitised. Dolomite has δ 13C values between 0.9 and 4.0‰ (PDB) and δ 18O values between −4.5 and −10.8‰ (PDB). Calcite has δ 13C values between 3.8 and 4.4‰ (PDB) and δ 18O values between −4.9 and −5.5‰ (PDB). These values suggest that the calcite represents a change in water composition and that dolomite and calcite cements do not precipitate from petroleum-derived fluids. However, geological fluids are trapped as aqueous and oil inclusions in the calcite cements. Three petroleum-aqueous inclusion assemblages were identified: pseudo-primary brown oil paired with brine inclusions and pseudo-primary yellow oil paired with low salinity water inclusions distributed in local concentrations; and secondary colourless oil paired with low salinity aqueous inclusions distributed in healed microfractures. The burial model, calibrated with bottom-hole temperatures, has been calculated using PetroMod ® 1D to generate the rock PT history under hydrostatic and lithostatic regimes. Reconstructed temperatures of initial trapping of fluid inclusion and calculated temperatures from δ 18O measured in dolomite and calcite cements are in good agreement. Data suggests that the reservoir was being filled at 97 °C–315 bar by heavy black oils accompanied by high salinity water during the Miocene period (11.6 m.y.). The maximum estimated pressure of 700 bar at 130 °C is reconstructed by petroleum inclusions trapping black oil and associated low salinity aqueous inclusions. These PT conditions were reached during the Pliocene (3–2m.y.). Present day reservoir conditions of 145 °C and 500 bar are recorded by reequilibration of most of the fluid inclusions of the two assemblages and correspond to hydrostatic pressure. The drop of pressure from 700 bar to 500 bar may be an explanation for the late stylolitisation.

中東地域下部白亜系炭酸塩岩油層における５点水攻法下の水付き現象とその地質学的要因

Premature water breakthrough was observed in a Lower Cretaceous carbonate reservoir under five spot pattern water injection in a Middle East oil field. Openhole log resistivity anomalies in recently drilled wells and time lapse pulsed neutron logs suggested preferential water movement in certain horizons. Reservoir heterogeneity depending on lithological variation is identified as a cause of the water breakthrough.Two high permeable lithofacies were defined by core and thin section observation. One is altered bioclast dominant coarse grainstone/packstone in the middle part of the reservoir. The other is very fine altered bioclastic peloidal grainstone/packstone in the upper part of the reservoir. These lithofacies are composed mainly of rarely micritized bioclastic grains with rigid framework preserving intergranuler porosity. Large molds and vugs associated with rudists in the upper part of the reservoir are locally connected and contribute to the fluid flow.Relative sea level change and paleo-topography are recognized as important factors to control lithofacies distribution. Areal distribution of the lithofacies shows aggradational stacking pattern and abrupt lateral lithofacies change particularly in the middle part of the reservoir. This suggests that simple carbonate ramp model currently applied is not appropriate for reservoir characterization purpose in this reservoir.

3-D Architecture Model of a Lower Cretaceous Carbonate Reservoir, Al Huwaisah Field, Sultanate of Oman: ABSTRACT

3-D Architecture Model of a Lower Cretaceous Carbonate Reservoir, Al Huwaisah Field, Sultanate of Oman: ABSTRACT

Constraining Diagenesis Using Fluid Inclusions in Cements from Petroleum Basins: Examples from North Sea and Middle East: ABSTRACT

Cements in petroleum reservoirs commonly contain inclusions filled with brine, hydrocarbon, or mixtures of both. The physicochemical conditions of cementation as well as the quality of the inclusion oil can be derived from microthermometric and fluorescence microspectrophotometric analysis of fluid inclusions. These data, when integrated with petrographic, geochemical, engineering, and burial history data, can constrain the timing and nature of both diagenetic events and oil migration. Brine and oil-bearing inclusions occur in quartz overgrowths from the Brent Sandstone, Northwest Hutton field, North Sea. Fluorescence analysis indicates that the inclusion oil is similar to the reservoired oil. Inclusion data define the reservoir conditions that existed during the initial stages of oil accumulation and concurrent quartz cementation. The abnormally high pressure of inclusion entrapment suggests that the reservoir was overpressured. Paleo-overpressuring probably helped preserve reservoir porosity by slowing compaction-related loss of porosity in coarse-grained reservoir sands. Brine, oil, and three-phase (brine, oil, and vapor) inclusions occur in burial-related calcite and dolomite cements from a Lower Cretaceous (Thamama) carbonate reservoir in the Middle East. Inclusion data indicate that these cements were precipitated from and simultaneously trapped an invading basinal brine that contained an immiscible component of hydrocarbon. The intersection of brine and oilmore » isochores in pore-throat space allows a unique determination of the time and depth of initial reservoir fill-up. The fill-up appears to coincide with the onset of peak oil generation from the source rocks believed to have supplied these reservoirs.« less

Distribution and Permeability of Stylolite-Bearing Horizons Within a Lower Cretaceous Carbonate Reservoir in the Middle East

Summary Stylolites and related pressure-solution features occur in many carbonate reservoirs. They are seams of insoluble residue that record the removal of rock by pressure dissolution. Stylolites may limit reservoir continuity by forming barriers or impedances to fluid flow. This core-based study documents both the distribution of stylolites and the variable impact of stylolite-bearing horizons on reservoir continuity for a Lower Cretaceous carbonate reservoir in the Middle East.