Search Results (8)

Qualitative schematic models of the Mishrif Formation, which have previously dominated the research, are inadequate for predicting reservoir production performance due to their inability to quantify spatial heterogeneity. In contrast to these earlier approaches, this study integrates core analysis, wireline logs, and 3D seismic data to not only describe but also quantitatively characterize the depositional elements and their spatial distribution. A novel methodology was developed to define nine distinct depositional elements from cored wells and then continuously identify them in uncored wells using unique pseudo-wireline log responses, a step not achieved in prior work. Furthermore, moving beyond previous qualitative models, 3D quantitative versions were constructed using Sequential Indicator Simulation (SIS) explicitly constrained by depositional geometries derived from 3D seismic inversion volumes. For the first time, these models reveal the quantitative spatial extent and evolution of these elements. Updating the 3D petrophysical property model using this new depositional framework resulted in a 15% increase in successful production history matches, demonstrating the direct and superior predictive power of this integrated quantitative approach for forecasting oil reservoir production performance. Full article

This paper demonstrates the comprehensive research of the target Middle Eastern carbonate oilfield on waterflooding technologies, including geological characteristics, integrated research, and principal development techniques. Geological research reveals that the Mishrif Formation in the B Oilfield is a gentle-sloping carbonate platform, with granular limestone serving as the primary reservoir rock and micrite limestone serving as the secondary reservoir rock. In addition, based on understandings drawn from geological characteristics and numerical simulation, the water flooding mode of IBPT, which can take full use of the gravity effect, has been proven to yield better sweep efficiency in the context of a thick and heterogeneous reservoir. Furthermore, a large-scale physical model experiment is designed to investigate the fluid migration between the producer and injector and indicates that the injected water migration is mainly divided into four phases, including a two-peak advance phase, a gravitational differentiation phase, a secondary bottom water phase, and a wellbore water coning phase. Subsequently, the principal techniques and corresponding optimized production responses of water flooding development are systematically illustrated, which consist of well type optimization, differentiated water injection strategies, injection pattern conversion, unstable water injection, selective well perforation, as well as tracer surveillance methodology. The outcomes of this study are directly derived from field performances and could provide concrete practical experiences for water flooding technology in the Middle East. Full article

Geophysical logging curves are crucial for oil and gas field exploration and development, and curve reconstruction techniques are a key focus of research in this field. This study proposes an inversion model for deep resistivity curves in marine carbonate reservoirs, specifically the Mishrif Formation of the Halfaya Field, by integrating a deep learning model called CNN-GRU-ATT, which combines Convolutional Neural Networks (CNN), Gated Recurrent Units (GRU), and the Attention Mechanism (ATT). Using logging data from the marine carbonate oil layers, the reconstructed deep resistivity curve is compared with actual measurements to determine reservoir fluid properties. The results demonstrate the effectiveness of the CNN-GRU-ATT model in accurately reconstructing deep resistivity curves for carbonate reservoirs within the Mishrif Formation. Notably, the model outperforms alternative methods such as CNN-GRU, GRU, Long Short-Term Memory (LSTM), Multiple Regression, and Random Forest in new wells, exhibiting high accuracy and robust generalization capabilities. In practical applications, the response of the inverted deep resistivity curve can be utilized to identify the reservoir water cut. Specifically, when the model-inverted curve exhibits a higher response compared to the measured curve, it indicates the presence of reservoir water. Additionally, a stable relative position between the two curves suggests the presence of a water layer. Utilizing this method, the oil–water transition zone can be accurately delineated, achieving a fluid property identification accuracy of 93.14%. This study not only introduces a novel curve reconstruction method but also presents a precise approach to identifying reservoir fluid properties. These findings establish a solid technical foundation for decision-making support in oilfield development. Full article

Evaluating irreducible water saturation is crucial for estimating reservoir capacity and developing effective extraction strategies. Traditional methods for predicting irreducible water saturation are limited by their reliance on specific logging data, which affects accuracy and applicability. This study introduces a predictive method based on fractal theory and deep learning for assessing irreducible water saturation in complex carbonate reservoirs. Utilizing the Mishrif Formation of the Halfaya oilfield as a case study, a new evaluation model was developed using the nuclear magnetic resonance (NMR) fractal permeability model and validated with surface NMR and mercury injection capillary pressure (MICP) data. The relationship between the logarithm mean of the transverse relaxation time (T_2lm) and physical properties was explored through fractal theory and the Thomeer Function. This relationship was integrated with conventional logging curves and an advanced deep learning algorithm to construct a T_2lm prediction model, offering a robust data foundation for irreducible water saturation evaluation. The results show that the new method is applicable to wells with and without specialized NMR logging data. For the Mishrif Formation, the predicted irreducible water saturation achieved a coefficient of determination of 0.943 compared to core results, with a mean absolute error of 2.37% and a mean relative error of 8.46%. Despite introducing additional errors with inverted T_2lm curves, it remains within acceptable limits. Compared to traditional methods, this approach provides enhanced predictive accuracy and broader applicability. Full article

The Cenomanian–Early Turonian Mishrif Formation is a great contributor to oil production in Iraq. Integrating petrographic, mineralogical, and wireline logging data from 52 wells, this study provides an improved understanding of the sequence stratigraphy, depositional evolution, and reservoir characteristics of the Mishrif Formation in the Mesopotamian Basin, south Iraq. Five types of facies associations are classified: lagoon, shoal, rudist bioherm, shallow marine, and deep marine. Such a classification allows convenient differentiation and interpretation of wireline logs. A sequence stratigraphic framework including five third-order sequences (Mhf 1 to Mhf 5) for the Mishrif Formation is established mainly using wireline logging data of close-distance wells, with the aid of cores and thin sections. Two end-member depositional evolution stages are recognized, from clinoform-like progradational shoal complexes in Mhf 1 within a shallow marine environment, to tidal channels in Mhf 2–3 within a lagoon environment. For Mhf 4–5, abrupt changes in facies associations from north to south indicate the development of an intra-shelf basin where organic-rich mudstones directly overlie the shallow marine grainstone shoals and lagoonal wackestones. Reservoir characteristics and compartmentalization are directly controlled by the sequence stratigraphic framework. Sequence boundaries are featured by wackestones and mudstones overprinted by cementation; they are regionally correlatable and work as regional barriers. Shoal complexes in Mhf 1 and tidal channels in Mhf 2–3 are the main reservoir units. Mudstones and wackestones are intra-reservoir baffles and become more frequently developed towards the south, reflecting the increasing water depth towards south. The characterization of the tidal channels, clinoform-like shoals, and intrashelf basinal deposits in the current study could benefit later development of the Mishrif Formation. Full article

The nature of carbonate rock’s heterogeneity under subsurface conditions is still under debate due to significant variations in mineral composition and changes in rock texture during/after diagenesis. However, several studies have utilized facies analysis and conventional sets of logs to develop a detailed description of reservoir rocks. This paper presents the design of a precise model for cretaceous carbonate reservoir characterization through micro and macro porous media and permeable zones and integrates lithological variation with more than 1800 measurements of porosity/permeability values along two bore wells in Amara Oilfield. This paper presents a detailed description of lithological and reservoir characterization in the Am1 and Am3 borewells form west to east, respectively. In the west, plugged samples were obtained from Mishrif formations, while in the east, the samples were obtained from the Khasib, Mishrif, and Yamama formations. The porosity and permeability distribution in the subsurface settings was divided into three porous–permeable zones in Am1 and Am3. Am1 in the west shows a greater porous–permeable zone than Am3 in the east of Amara Oilfield. The permeability and porosity in Am1 measured up to 591 md and 29.6%, while in Am3, values up to 352 md and 24.2% were recorded, respectively. Therefore, the porous–permeable subsurface distributions and their petrophysical mapping for different kinds of reservoirs reveal that the porosity and permeability measurements decreased from west to east; however, there were a few fluctuations corresponding to increases and decreases in the porosity and permeability values that were mostly controlled by the involvement of diagenetic fluids, which were resulted from the heterogeneity of carbonate rocks. Full article

The Mishrif Formation in X Oilfield in Iraq is heterogeneous and has prominent development contradictions, and the development plan required urgent adjustment. Based on data regarding the core, cast thin sections, physical property, mercury injection experiments, and development performance, the main geological factors causing the unbalanced development of the Mishrif Formation are identified, and the corresponding development strategy is proposed. The results show that the High Flow Zones (HFZs) are the main geological factors causing unbalanced production in the thick bioclastic limestone reservoir. There are three kinds of HFZs in MA, MB1, and MB2 intervals, namely, the point shoal type, the tidal channel type, and the platform margin shoal type. All HFZs have different scales and distribution patterns. HFZs have ultra-high permeability and large permeability differences with the surrounding reservoir. During development, the oil mainly comes from HFZs, and the considerable reserves in the low permeability reservoir surrounding the HFZs are difficult to develop. The size of the pore throat of the HFZs greatly varies, and permeability is mainly dominated by the mega-pore throat (>10 μm) and the macro-pore throat (2.5~10 μm). In water flood development, the injected water rapidly advances along the mega-pore throat and the macro-pore throat, and the oil in the micro-pore or medium-pore throats are difficult to be displace. It can be concluded that the Mishrif Formation is vertically heterogeneous. The connectivity of HFZs in different intervals greatly varies. As a result, the Mishrif Formation is divided into three development units, MA, MB1, and MB2 + MC, and production wells are deployed in HFZs. The MA adopts a reverse nine-point injection-production pattern, for which the well spacing is 900 m using a vertical well, and the injection well should avoid the HFZs near the faults. The MB1 adopts an irregular five-point injection-production pattern using a vertical well, and the injection wells are deployed at the edge of the tidal channel or in the lagoon. MB2_1 deploys horizontal production wells, for which the well spacing is 900 m. Horizontal production wells, for which the well spacing is 300 m, are deployed in the lower MB2, and the lateral horizontal production wells are converted into injection wells after water breakthrough, and the horizontal wells deployed in the lower part of MC should moderately inject water. Full article

The effect of stylolite caused by the pressure dissolution process on the reservoir petro-physical properties is still controversial. This study aims to reveal the effect of stylolite on the porosity and permeability of packstone and wackestone in the Mishrif Formation from the Ah oilfield in the Middle East. Based on the observation of thin sections and cores, X-ray diffraction analysis and porosity and permeability measurement, the lithofacies, diagenesis and patterns of stylolites have been investigated. There are six lithofacies in the Mi4 member, including bivalve green algae packstone, green algae packstone, pelletoid green algae packstone, echinoderm packstone, rudist packstone, planktonic foraminifera wackestone and bioclastic wackestone. The mechanical compaction and pressure dissolution could be observed in these lithofacies, with the development of dissolution seams and stylolites. The density of stylolite has a relationship with the lithofacies and early cementation. The boundary between the echinoderm packstone and the green algae packstone mostly developed as stylolites. There are four types of stylolite on the cores. Type A is the wave-like stylolite developed at the boundary between the echinoderm packstones and green algae packstones. Type B is the zigzag stylolite with high amplitude in the green algae packstones. Type C is the stylolites with low amplitude in the bioclastic wackestones. Type D is the high-angle stylolite, which is oblique to the bedding plane. The permeability of reservoir rocks could be improved by dissolution along the type B stylolite, while the type A and type C stylolite have little effect on permeability. The permeability of green algae packstone and echinoderm packstone will decrease with the development of stylolites. The porosity and permeability of bivalve green algae packstone will decrease after stylolitization, resulting from the relatively high density of stylolite. The physical properties of bioclastic wackestone could be improved by the bioturbation and formation of stylolite. According to the analysis of production performance in the same lithofacies, the occurrence of stylolites could result in the development of oil baffles. This study could be extended to evaluate the effect of stylolite in carbonate reservoir rocks. Full article