Carbonate Reservoir Model Research Articles

Carbonate reservoir characterization and permeability modeling using Machine Learning ـــ a study from Ras Fanar field, Gulf of Suez, Egypt

Predicting facies and petrophysical properties along and between wells is challenging in carbonate reservoir modeling. In the Nullipore carbonate reservoir, Ras Fanar field, depositional and long-term diagenetic processes result in a high degree of heterogeneity and complex distribution of facies, which in turn affect the reservoir quality. This provides a significant obstacle to building accurate geological models. This study integrates thin sections, routine core analyses, and well logging data to overcome such difficulties and model the Nullipore carbonate facies and permeability. The detailed petrographic analysis revealed the existence of seven microfacies in the reservoir, which are summed up into three facies associations (FAs), each of which represents a specific reservoir rock type (RRT): (1) supratidal FA, (2) intertidal FA, and (3) shallow subtidal FA. The three FAs were correlated with the gamma-ray logs to create facies logs for the studied wells, which were further populated via the Truncated Gaussian Simulation method. Cross-validation was used to evaluate the model's accuracy. The analysis of the available core data infers that the three RRTs are prospective and have a wide permeability distribution. However, RRT3 constitutes the best reservoir quality. The sedimentological analysis revealed that the long-term diagenetic events, involving the dolomitization of limestone and the dissolution of allochems have a major role in improving the pore connectivity and permeability of the reservoir. Fracture characterization discloses that fractures play a significant role in fluid storage and migration. Three Machine Learning (ML) models, including Adaptive boosting (AdaBoost), Gradient Boosting (GB), and Extreme Gradient Boosting (XGB), were developed to integrate the RRTs, porosity, and permeability to improve permeability prediction. Statistical analysis revealed that the XGB model outperforms other models and exhibits the highest prediction performance. The present study provides further insights into the characterization and modeling of facies and permeability of complex carbonate reservoirs. It can be applied in similar geological settings to better interpretation of depositional and diagenetic controls on reservoir quality assessment and aid in the field development plan.

A novel hybrid enhanced oil recovery technique to enhance oil production from oil-wet carbonate reservoirs by combining electrical heating with nanofluid flooding

Enhanced Oil Recovery provides a promising technique to maximise fossil fuel recovery from existing resources, and when used in conjunction with Carbon Capture and Storage/Utilisation provides a way to support a transition to alternative cleaner fuels. A hybrid Enhanced Oil Recovery method by a combination of electrical heating and nanofluid flooding was applied to oil-wet carbonate reservoirs and assessed in terms of the oil production, zeta potential, contact angle, pellet compaction, interfacial tension, and pH values. The hybrid technique consisted of a combination of direct current (up to 30 V) and iron oxide (Fe2O3) or magnesium oxide (MgO) nanofluids. Both nanofluids were injected into oil-wet Austin chalk – our laboratory model of an oil-wet carbonate reservoir – and then electrical heating was started, or vice versa. Introducing electrical heating first increased oil recovery by up to 27% in seawater compared to 16% in deionised water. When Fe2O3 nanofluid was injected, oil recovery further increased to 32% in seawater and 24% in deionised water. The contact angle and zeta potential decreased from 124° to 36° and from −24.4 to −23.7 mV, respectively, when nanofluid was injected in seawater, leading to better nanofluid stability and penetration into the carbonate rock as shown by increased pellet porosity from 6.6% to 14.8%. Moreover, it was found that the interfacial tension was reduced from 72 to 32.7 mN/m in the pre-magnetised samples with Fe2O3 NPs injection compared to 33.2 mN/m in the samples with MgO injection. It was found from our experiments that the effect of the generated electricity on the surface charge was of a temporary nature as the zeta potential of the rock returned to its original value as soon as the power was disconnected. The mechanism underlying the hybrid Enhanced Oil Recovery EOR technique from the laboratory findings was found to be based on electrowetting and nanofluid adsorption. Results indicate that the technique is promising for further improving oil recovery and securing energy supply during the transition to net zero.

An echo state network approach to data-driven modeling and optimal control of carbonate reservoirs with uncertainty fields

Previous studies of reservoir simulation have shown that it is required to have every inherent carbonate reservoir physics available at the model development phase. However, this process while ideal is computationally intensive and time consuming especially for complex geological fields. In this study, Echo State Network (ESN) is proposed to predict two cases of reservoir waterflooding with integrated uncertainty properties in unstructured physical dimension and log-normal permeability fields. The generalization efficiency of ESN with respect to uncertainties in injection and production data is also investigated by tuning the ESN reservoir size (N). Consequently, adjoint based method is used to optimize the Net Present Value (NPV) via obtained injection well controls. Observation revealed that the developed ESN exhibits superior predictive accuracy in scenarios of low geological uncertainties, achieving an average test accuracy of 90.79%, and then declining to 86.19% as the uncertainty level is increased. Also, N is found to be significant in terms of ESN generalization efficiency with N = 40 achieving higher performance compared to N = 20, thereby validating its influence on ESN reservoir state to adapt to current data history during training. Lastly, the optimized scenario, derived from the initial well control predictions, demonstrated a higher NPV when compared with the base scenario of the developed oil reservoir model.

Fracture-vuggy carbonate reservoir characterization based on multiple geological information fusion

The complexity and strong heterogeneity of carbonate reservoirs with fracture-vuggy structures present significant challenges in reservoir characterization. To address these challenges, we propose a novel multi-element information fusion modeling approach. This approach is designed to integrate multiple methods and incorporate multi-probability fusion at various facies and scales, thereby bridging the gap between geological information and reservoir modeling. Our methodology involves four key steps. First, the statistics between frequency of karst and geological information are acquired, and we quantify the statistics to regression equations. Second, these regression equations are transferred to probability bodies. The probability bodies can be applied in modeling as a soft control. But just one single body can be input in modeling process. Third, multiple probability bodies are fused into a fusion probability body by a probability fusion algorithm, which can keep the potential information of probability bodies. Finally, we apply the probability body in modeling workflow. By this way, the fusion method bridges the gap between geological information and modeling. The model established through our proposed method showed a significant level of consistency with reservoir re-evaluation, achieving an impressive 90% degree of alignment. Furthermore, the history match analysis revealed a high correlation, indicating the model's reliability. The method effectively integrates various scales and types of geological information, offering an accurate approach to complex carbonate reservoir modeling.

Characterization of silicification and dissolution zones by integrating borehole image logs and core samples: a case study of a well from the Brazilian pre-salt

Precise knowledge of the spatial distribution patterns of non-matrix porosity zones and the establishment of the geological factors controlling their evolution are crucial for building more accurate carbonate reservoir models and improving hydrocarbon production. The occurrence of intervals affected by significant carbonate dissolution may result in drilling fluid loss and time-consuming drawbacks during well construction. Vug or cave-rich reservoirs may exhibit excess permeability and extremely high initial flow rates. Similar situations have been reported in exploration activities in the Brazilian pre-salt plays, where evidence of dissolution and other burial diagenetic processes, such as severe silicification and dolomitization, are common. In this study, we investigate evidence of major post-depositional changes in the lacustrine carbonate reservoirs of the Barra Velha Formation, which comprises the most prolific hydrocarbon play in Brazil. Using a comprehensive database consisting of both core samples and well-log data from a vertical well in the Santos Basin, we have characterized, at multiple scales, reservoir zones affected by silicification and carbonate dissolution. In addition, we have performed a petrophysical evaluation of the reservoir to understand the impact of such processes on porosity and permeability development. The results suggested an intimate relationship between silicification and dissolution processes, which can be associated with late fluid percolation under a deep burial flow regime. The occurrence of silicified and vuggy beds, associated with specific zones and lithofacies, indicates an important degree of stratigraphic control on fluid percolation and lateral migration. Furthermore, the presence of fractures at discrete stratigraphic levels has preferentially influenced the development of high-permeability zones, including metric-scale fracture-related conduits. This study contributes to the general knowledge of carbonate reservoirs affected by silicification and dissolution while providing support for the recognition of such processes in partially- or non-cored wells.

Depositional and diagenetic modeling of the Margala Hill Limestone, Hazara area (Pakistan): Implications for reservoir characterization using outcrop analogues

Understanding the depositional and diagenetic processes is critical for the modeling and resource potential of carbonate reservoirs. The Lower Eocene Margala Hill Limestone forms hydrocarbon resources in Pakistan characterized by heterogeneity; however, there is a lack of details about the diagenetic modifiers of this formation in the southeastern Hazara, Pakistan, and an integrated study of outcrop analogues can help in the better exploitation of these important resources. This work focuses on clarifying of depositional environment, diagenesis, and reservoir characterization in five stratigraphic sections of Lower Eocene Margala Hill Limestone in the southeastern Hazara, Pakistan. The integrated sedimentological and stable isotopes analysis were used in this study to better understand reservoir characterization and potential. This study revealed that the Margala Hill Limestone in the studied outcrops is medium-to thickly bedded, nodular in places, and fractured. Based on petrographic studies and allochems to matrix ratio, six microfacies (wacke-to packestone) were identified in the studied formation. The Margala Hill Limestone was deposited in the inner to middle ramp setting. The various types of cement observed in the Margala Hill Limestone are non-Ferroan cements (i.e., granular, blocky, drusy, and microcrystalline) and ferroan cements are also observed. The observed diagenetic processes are cementation, biogenic alteration, neomorphism, compaction, dolomitization, fracturing, dissolution, and nodularity. The diagenetic and stable isotopes (δ13C and δ18O) studies indicate that the Margala Hill Limestone was affected by marine, meteoric, and burial diagenesis. The recorded porosity types include intragranular, intergranular, moldic, vuggy, and fractured porosity, indicating that the Margala Hill Limestone shows a good secondary reservoir for hydrocarbon accumulation. This study could prove a potential carbonate reservoir and help in the future exploration of the under-explored Eocene carbonates in the southeastern Hazara area, Pakistan.

Creation a permeability array for simulation model of a complex carbonate reservoir with zonal heterogeneity

The study presents an approach to creating a simulation model of a complex reservoir based on the integration of multi-scale studies that make it possible to understand the alternation of different types of reservoirs along the lateral and vertical. For various types of reservoir, petrophysical dependences of permeability on porosity were built, which became the basis for the original permeability array of the model. The refined permeability array made it possible to significantly improve the history matching to the actual data after the first iteration. In this research, an array of Voronoi polygons was built, which allowed further targeted modification of petrotypes in the area of wells, taking into account the actual dynamics of well rates. Based on the results of calculations, by local modifications, the cumulative oil and liquid production were matched. Proposed approach of fissures distribution made it possible to reduce the degree of uncertainty of filtration parameters during history matching of the model to actual development data and increase the reliability of forecast calculations. Keywords: carbonate reservoir; reservoir simulation modeling; permeability fracturing; reservoir properties.

3D geological modeling for Yamama reservoir in Al-Nasiriyah oil field Southern Iraq

The geological modeling of an oil-bearing reservoir, which specifies the lithology and analyzes the petrophysical parameters of complex reservoir, its being created using Petrel software to construct reservoir models that describe and estimate porosity and water saturation distributions. 3D modeling of carbonate reservoirs has proven to be a highly effective technique for evaluate the economic benefit of the reservoir by estimating the formation petrophysical properties and calculating the oil reserves. The study aims constructed on evaluated Yamama formation in Four drilling wells (Nasiriyah-1, Nasiriyah-3, Nasiriyah-4, and Nasiriyah-5) entering the Yamama Formation of the Al-Nasiriyah field. In Al-Nasiriyah Oil field, and within the Lower Cretaceous Stratigraphic Column in the south of Iraq, the Yamama Formation is one of the most important reservoirs that deposited into shallow marine habitats throughout the (Valanginian- Early Hauterivian) period, that made up of reservoir and impermeable barrier units in the Al-Nasiriyah field, Yamama Reservoir units are divided into three reservoir units (YA, YB, and YC), with the YB reservoir unit subdivided into (YB1, YB2, and YB3) subunits. The main reservoir units are separated by four sharp impermeable barriers represented by (B1, B2, B3, and B4).

Porosity estimation of a geothermal carbonate reservoir in the German Molasse Basin based on seismic amplitude inversion

The Molasse Basin is one of the most promising areas for deep geothermal exploitation in Germany and the target horizon is the aquifer in the Upper Jurassic carbonates. Carbonate deposits can be very heterogeneous even over a small area due to diagenetic processes and varying depositional environments. The preferential targets for geothermal exploitation in carbonate deposits are fault zones, reef facies and karstified areas, since they are expected to act as hydraulically permeable zones due to high porosity and high permeability. Therefore, identifying these structures and characterizing, e.g., their internal porosity distribution are of high importance. This can be accomplished using 3D reflection seismic data. Besides structural information, 3D seismic surveys provide important reservoir properties, such as acoustic impedance, from which a porosity model can be derived. In our study area in Munich we carried out a seismic amplitude inversion to get an acoustic impedance model of the Upper Jurassic carbonate reservoir using a 3D seismic data set, a corresponding structural geological model, and logging data from six wells at the ‘Schäftlarnstraße’ geothermal site. The impedance model and porosity logs were than used to calculate a porosity model. The model shows a wide porosity range from 0 to 20% for the entire reservoir zone and the lithology along the wells reveals that dolomitic limestone has the highest porosities and calcareous dolomite has the lowest porosities. The study area is cut by a large W–E striking fault, the Munich Fault, and the footwall north of it shows higher porosities and more intense karstification than the hanging wall to the south. Considering the entire study area, an increase in porosity from east to west is observed. Furthermore, we identified a complex porosity distribution in reef buildups and pinnacle reefs. The reef cores have mostly low porosities of, e.g., < 3% and the highest porosities of up to 7 to 14% are observed at the reef caps and on the reef slopes. The reef slopes show a characteristic interfingering of the reef facies with the surrounding bedded facies, which indicates a syn-sedimentary reef development with slightly varying build up growth rates. We also assessed the reservoir quality with regard to porosity distribution and determined areas with moderate to good quality for geothermal exploitation by defining porosity evaluation levels. The porosity evaluation maps show that the carbonate rocks of Berriasian to Malm zeta1 are preferential targets for exploitation, especially in the footwall of the Munich Fault and to the west of the hanging wall, because these areas are characterized by high porosities due to intense karstification of bedded and massive facies, although the latter is mainly restricted to reef caps and reef slopes.

Petroelastic modeling of carbonate reservoirs in the view of different void types

Background. Fractures present in carbonate rocks facilitate fluid flow within void spaces. Each type of voids can have a different effect on rock elastic properties, which, in turn, allow the characteristics of voids to be estimated by assessing the velocity of elastic waves. In this paper, an effect of pores and fractures on the velocity of elastic waves is analyzed by petroelastic modeling. An example of solving an inverse problem is presented, involving the determination of fracture porosity and relative fracture opening using the data on elastic wave velocity and hydrocarbon reservoir density obtained during geophysical well logging.Aim. To increase the accuracy of experimental data on the velocity of elastic waves that propagate across hydrocarbon carbonate reservoirs by assessing the pore and fracture characteristics of voids.Materials and methods. The effective medium theory was used as an efficient way to evaluate physical, including elastic, properties based on rock composition and microstructure. Using Berryman’s self-consistent method, we created a model of rock elastic properties, or a petroelastic model, the void space in which was represented by isometric pores and fractures. This model was applied to a well in a petroleum province in West Siberia.Results. The effect of characteristics determining the void space of porous-fractured rocks on the velocity of elastic waves was defined. Velocity surfaces were constructed in accordance with changing parameters of the model, i.e. fracture porosity and fracture aspect ratio. The obtained theoretical and experimental data were compared in order to determine fracture development zones and to evaluate volume concentration and relative fracture opening in these zones.Conclusion. The effect of pores and fractures on elastic wave velocity in porous-fractured carbonate reservoirs was studied by petroelastic modeling. The zones of excessive fracturing were defined and the parameters of volume concentration and relative fracture opening were determined using the data obtained by geophysical well logging in a petroleum province in West Siberia.

Integrated Reservoir Model and Differential Stimulation Modes of Low Permeability Porous Carbonate Reservoir: A Case Study of S Reservoir in X Oilfield in Iraq

The S reservoir in the X Oilfield in Iraq has great development potential due to its rich geological reserves. However, the low permeability and strong heterogeneity of the reservoir lead to great differences in reservoir stimulation performance. In this study, an integrated reservoir model and differential stimulation mode are put forward to solve the above problems. First, the feasibility of fracturing is evaluated by laboratory experiments. Second, an integrated reservoir model is established, which mainly includes a rock mechanics model, fracturing simulation model, and numerical simulation model, and correct the integrated model by fracturing operation curves and production dynamic curves. Third, three types of stimulation areas are classified according to the combination of sweet spot types, and three different stimulation modes are proposed. In conclusion, a small-scale stimulation mode should be applied in the Type I area to maximize economic benefits. In the Type II area, the medium-scale stimulation mode should be performed to ensure certain productivity while achieving certain economic benefits. In the Type III area, the large-scale stimulation mode should be employed to obtain certain productivity while economic benefits must be above a limit. The differential stimulation model proposed in this paper has made a great reference for the efficient development of low-permeability carbonate rocks.

Scale, origin, and predictability of reservoir heterogeneities in shallow-marine carbonate sequences: A case from Cretaceous of Zagros, Iran

This study presents an integrated reservoir heterogeneity analysis of an Iranian carbonate oil reservoir (Sarvak Formation) in the Zagros region. Both static and dynamic aspects of reservoir heterogeneities are considered by integration of routine–special core data and geological attributes (i.e., depositional facies and textures, diagenetic alterations, pore types, and sequence stratigraphic positions). Core porosity and permeability, mercury injection capillary pressure, and scanning electron microscopy data are used along with the results of petrographic studies to define petrographic rock types, pore types, hydraulic flow units, and reservoir to non-reservoir (baffle or barrier) zones in the studied reservoir. Spatial facies distribution (facies variability) and development of disconformable surfaces (sequence boundaries) controlled the large-scale reservoir heterogeneities. On the other hand, variations in microscopic characteristics of depositional facies (i.e., textures and structures) and diagenetic features (e.g., intensity of dissolution, cementation and compaction) formed the small-scale reservoir heterogeneities. The best productive zones of this reservoir are meteorically-dissolved reef-talus and shoal facies, accumulated within the regressive systems tracts of third-order sequences. Intensively compacted and cemented facies formed the effective vertical barrier/baffle zones in this reservoir, especially within the transgressive systems tracts and around the maximum flooding surfaces. Results of this study revealed that the stratigraphic modified Lorenz plot (SMLP) is a useful tool for the discrimination of large-scale reservoir heterogeneities, while hydraulic flow units and Winland rock typing approaches are applicable for the identification of small-scale heterogeneities. This study indicated that the large-scale heterogeneities of carbonate reservoirs are predictable in a sequence stratigraphic framework, especially in the third-order scale. Such a heterogeneity model calibrated in the sequence stratigraphic framework provides a reliable basis for reservoir modeling of heterogeneous carbonate reservoirs in the field-to regional scales.

The design of an open-source carbonate reservoir model

This work presents a new open-source carbonate reservoir case study, the COSTA model, that uniquely considers significant uncertainties inherent to carbonate reservoirs, providing a far more challenging and realistic benchmarking test for a range of geo-energy applications. The COSTA field is large, with many wells and large associated volumes. The dataset embeds many interacting geological and petrophysical uncertainties in an ensemble of model concepts with realistic geological and model complexity levels and varying production profiles. The resulting number of different models and long run times creates a more demanding computational challenge than current benchmarking models. The COSTA model takes inspiration from the shelf-to-basin geological setting of the Upper Kharaib Member (Early Cretaceous), one of the most prolific aggradational parasequence carbonate formations sets in the world. The dataset is based on 43 wells and the corresponding fully anonymised data from the northeastern part of the Rub Al Khali basin, a sub-basin of the wider Arabian Basin. Our model encapsulates the large-scale geological setting and reservoir heterogeneities found across the shelf-to-basin profile, into one single model, for geological modelling and reservoir simulation studies. The result of this research is a semi-synthetic but geologically realistic suite of carbonate reservoir models that capture a wide range of geological, petrophysical, and geomodelling uncertainties and that can be history-matched against an undisclosed, synthetic ‘truth case’. The models and dataset are made available as open-source to analyse several issues related to testing new numerical algorithms for geological modelling, uncertainty quantification, reservoir simulation, history matching, optimization and machine learning. Supplementary material: supplementary data associated with this article can be found in the data repository for the COSTA model available at https://doi.org/10.17861/6e36e28d-50d9-4e31-9790-18db4bce6e5d and supplementary material is available at https://doi.org/10.6084/m9.figshare.c.5823571

Petrology, mineralogy and geochemistry of Ordovician rocks in the southwest of Tarim Basin, implications for genetic mechanism and evolution model of the hydrothermal reformed-paleokarst carbonate reservoir

Paleokarst carbonate reservoir plays an important role in the exploration of oil and gas from shallow to ultra-deep strata. Multistage karstification is superimposed to form the present ultra-deep karst-hydrothermal reformed carbonate reservoirs in the Yubei area of the Tarim Basin. Based on petrology identification, stable carbon and oxygen isotope analysis, inductively coupled plasma mass spectrometry (ICP-MS), and Laser Ablation inductively coupled plasma mass spectrometry (LA-ICP-MS), we investigated paleokarst periods, chemical property of hydrothermal fluids, and the evolution model and formation mechanism of paleokarst-hydrothermal reformed Ordovician carbonate reservoirs. The results show that the Ordovician strata experienced five periods of karstification from the middle Caledonian period to the late Himalayan period. The Caledonian quasi-contemporaneous karst and the Hercynian epigenetic karstification provided the most fundamental pore – fracture framework for carbonate reservoirs, and the later multistage deep burial karstification re-transformed the established reservoir space by hydrothermal dissolution under thermochemical sulfate reduction (TSR) reaction. It is proposed that the thermal convection between the hydrothermal fluids from the upper mantle and carbonate rocks formed two kinds of hydrothermal fluids in Ordovician strata. The first kind of hydrothermal fluid is performed with a SiO2-enriched fluid under the acidic environment based on TSR, forming siliceous cements and hydrothermal dissolution pores in the Lower Ordovician strata. The second kind of hydrothermal fluids appeared as an alkaline CO32—enriched fluid with the reversible reaction between HCO3− and CaCO3, forming hydrothermal calcite and dolomite near the migration channel in Upper Ordovician carbonate rocks. The periodic changes of in situ trace element concentrations of multistage quartz fillings indicated that paleokarst reservoirs are controlled by thermal convection under episodic tectonic activity. As a summary, we established the migration pattern of hydrothermal fluids in the thin section scale and the evolution model of the hydrothermal reformed paleokarst reservoirs in basin scale.

Research on 3D geological modeling of fractured-vuggy carbonate reservoirs

Fractured-vuggy carbonate reservoirs are mainly composed of holes, caves, and fractures, with large disparity in scale, irregular shape, and discontinuous distribution. Quantitatively depicting the distribution of holes, caves, and fractures in three-dimensional space has always been a technical problem in the development of this type of reservoir, and there is currently no effective geological modeling method. Taking the Yijianfang Formation in the Halahatang area of the Tarim Basin as an example, this paper proposes to model the cavities and fractures separately. The hole model is generated by seismic resampling, and the attribute model uses the inverted porosity as the data volume combined with dynamic and static data constraints to simulate and generate. There are two main methods for fracture modeling. One is deterministic fracture modeling, which is mainly for large-scale fractures; the other is random fracture modeling, which is mainly for small-scale fractures. The deterministic fracture modeling method is based on the seismic data, by extracting the fracture slices of the seismic ant body data, combining the fracture characterization results, screening the fractures, and finally generating a large-scale fracture network; finally integrating hole, the hole model and fracture attributes model to establish a geological model of fracture-cavity reservoirs. Model the cavities and fractures separately was used to drill well Pro1 in yijianfang Formation, revealing that the target zone was 28 meters, and the high yield oil flow was obtained by sidetracking the high point target, which proved that the simulation results were credible.

Seismic geomorphology of submarine landslides in the Chalk Group of the Danish Central Graben: implications for reservoir potential

Abstract This study documents a variety of deposits created by submarine landslides within the Upper Cretaceous to lowermost Paleocene Chalk Group in the Danish Central Graben and investigates the impact of remobilization on porosity. Improved visualization of the landslides in 3D seismic data compared with previous studies was facilitated by better seismic data quality for the Chalk Group, the availability of a large stack of stratigraphy-consistent horizons and the use of spectral decomposition data. The illustrated examples are chosen to reflect the spectrum of deformation styles seen in the chalk and all have a well penetrating the affected succession. They include a large collapse (375 km 2 ) of an inversion ridge within the Kraka and Gorm formations, a field of large slide blocks (100–1000 m, 10–26 m) of likely lowermost Danian age embedded in the uppermost Ekofisk Formation, a debris flow system within the uppermost Tor Formation probably originating from the Ringkøbing–Fyn High and fine-grained bottom current sediment waves within the lowermost Danian Ekofisk Formation. In general, porosities are higher (10–25 porosity units) in the remobilized chalk compared with time-equivalent pelagic chalk in nearby reference wells. In earlier studies this has been linked to lack of bioturbation (resulting in limited grain repacking) in the remobilized chalks owing to high sedimentation rates, resulting in a relatively open fabric during initial burial. In contrast, surrounding and covering pelagic deposits could be much more effectively bioturbated, leading to tighter grain packing during burial. The insights of this study help in the seismic characterization of mud-grade carbonate oozes and have important applications in the reservoir modelling of mud-grade carbonate reservoirs (also in light of carbon capture and storage), and in palaeo-reconstructions of pelagic seafloors since submarine landslides provide kinematic indicators.

Production Improvement via Optimization of Hydraulic Acid Fracturing Design Parameters in a Tight Carbonate Reservoir

Hydraulic fracturing can be utilized to extract trapped hydrocarbon where integrated fracture networks do not exist for sufficient production. In this work, design parameters of a hydraulic acid fracturing of a tight carbonate reservoir in the Middle East were optimized. The effect of optimized hydraulic fracturing on production performance and rate was investigated. Using the petrophysical well logs, formation integrity tests, core data the Mechanical Earth Model (MEM) of the tight carbonate reservoir was created, which resulted in rock mechanical properties and in-situ stresses. The other required parameters for fracturing design were either measured or found from empirical correlations. Following a candidate selection of suitable layers for fracturing, the input parameters were loaded in GOHFER software to design and optimize the fracturing job. Finally, the production forecast was performed and compared with current conditions. The injection parameters (flow rate, total volume, and number of stages) of the fracturing fluid (composed of guar and CMHPG and polymer with 15% HCL acid) were optimized to reach optimum resultant fracture geometry. Finally, optimized injection parameters were found at the injection flow rate of 18 barrels per minute, total injection volume of 90 K-gal, and three stages of injection. Using the optimal injection parameters, the optimized fracture geometrical sizes were determined: the fracture half-length (Lf): 148 m (486 ft), fracture height (Hf) of 64 m (210 ft) and fracture width (Wf) of 0.0962 in. Finally, the effect of this stimulation method on future production performance was investigated. The well production rate showed an increase from 840 STB/Day (before fracturing) to 1270 STB/Day (post fracturing). This study contributes to the practical design and optimization of hydraulic fracturing in the tight carbonate formation of the investigated oilfield and the other potential fields in the region. The results showed that this stimulation method can efficiently improve production performance from reservoir formation.

Permeability prediction of heterogeneous carbonate gas condensate reservoirs applying group method of data handling

Carbonate petroleum reservoirs typically have lower permeabilities and recovery factors than sandstone reservoirs, so the natural fractures they often incorporate have positive impacts on resource recovery and fluid production rates. Quantifying effective permeability, incorporating contributions from pores and fractures, is therefore essential in the reservoir characterization and flow-regime modelling of carbonate reservoirs. This research applies a robust machine-learning forecasting model to predict permeability (K) for heterogeneous carbonate gas condensate reservoirs. A 212-point dataset from six gas-condensate carbonate reservoirs (Russia and Iran) is compiled. The input variables considered are porosity (Φ, %), specific surface area (Sp, 1/cm) and irreducible water saturation (Swir, %). These variables are assessed using four machine learning models: group method of data handling (GMDH), polynomial regression (PR), support vector machine (SVR), and decision tree (DT) to predict permeability. The GMDH algorithm, a polynomial neural network with a customized architecture is developed, such that it displays increased prediction accuracy and improved learning capabilities. All four models developed in this study substantially improve upon K predictions derived from established empirical correlations. The GMDH model also outperforms the other models in respect of K prediction accuracy using Φ, Swir, and Sp as input variables. It achieves permeability prediction accuracy for the multi-field dataset evaluated with a root mean squared error (RMSE) and coefficient of determination (R2) for the training and testing of the best model (GMDH) of RMSE = 9.2 mD and R2 = 0.9988; RMSE = 0.4 mD and R2 = 0.9972, respectively. The model can be readily adapted for application to other field datasets to estimate K from limited well-log and/or core data.

Theoretical exploration of water injection gravity flooding oil in ultra-deep fault-controlled fractured-cavity carbonate reservoirs

Based on the analysis of geological characteristics of ultra-deep fault-controlled fracture-cavity carbonate reservoirs and division of reservoir units, two physical models were made, and physical simulations of oil displacement by water injection were carried out to find out water flooding mechanism in the fault-controlled fracture-cavity carbonate reservoir under complex flow state. On this basis, a mathematical model of fault-controlled carbonate reservoir with coexisting seepage and free flow has been established. Pilot water injection tests have been carried out to evaluate the effects of enhancing oil recovery by water injection. The results show that: fault-controlled fracture-cavity carbonate reservoir units can be divided into three types: the strong natural energy connected type, the weak natural energy connected type and the weak natural energy isolated type; the fault-fracture activity index of the fault-controlled fractured-cavity body can effectively characterize the connectivity of the reservoir and predict the effective direction of water injection; the mathematical model of fault-controlled carbonate reservoir with coexisting seepage and free flows can quantitatively describe the fluid flow law in the fracture-cavity body; the water injected into the fault-controlled fracture-cavity body is weakly affected by the capillary force of the lithologic body, and the oil-water movement is mainly dominated by gravity. The development modes of single well water injection, unit water injection, and single well high pressure water injection proposed based on the connection structure of fracture- cavity space and well storage space configuration are confirmed effective by pilot tests, with obvious water injection gravity flooding effect.

Micromechanical modeling of ultrasonic velocity for pore-structure and porosity characterization considering anisotropy in carbonate samples

This work presents an approach to characterize the pore-structure and anisotropy in carbonate samples based on the Effective Medium Method (EMM). It considers a matrix with spheroidal inclusions which induce a transverse anisotropy. The compressional wave (VP), vertical (VSV) and horizontal (VSH) shear wave velocities are estimated taking into account parameters as characteristic length, frequency, angle of wave incidence, aspect ratio, mineralogy, and pore-filling fluid to predict pore shape in carbonates. Ranges of aspect ratios are shown to discriminate different pore types: intercrystalline, intergranular, moldic, and vuggy. The angle of wave incidence is a determinant parameter in the estimation of VP(0º, 45º, 90º), VSV(0º) and VSH(90º) to calculate dynamic anisotropic Young’s modulus (E33) and Poisson’s ratio (v31), as well as the Thomsen parameters, Epsilon, Gamma and Delta for quantification of the anisotropic pore-structure. The obtained results establish that the size, as well as the pore-structure, have a more significant impact on the elastic properties when the porosity takes values greater than 4% for the three frequencies, ultrasonic, sonic, and seismic. This investigation predicts the pore-structure and pore-size to improve characterization and elastic properties modeling of carbonate reservoirs. Validation of results includes porosity measurements and ultrasonic velocity data for different carbonate samples.