Fig 4 - uploaded by Ali E. Farag
Content may be subject to copyright.
A detailed composite wireline logs of the two wells, with the tops of the main Apollonia members (including pay zone members).
Source publication
Prediction of the formation pore pressure is considered as a significant simulation process during the drilling and production phases of the carbonate reservoir. The deficiency in this prediction allows for the occurrence of many troubles like blowouts, kicks, hole washouts, wellbore breakout, and stuck pipe. The most common conventional methods fo...
Context in source publication
Similar publications
Pipe structures are considered as fluid conduits beneath cold seeps. These structures have been observed in many geological settings and are widely accepted as the most critical pathway for fluid migration. One of such pipe structures in the Haima cold seep region is investigated herein. The pipe structure extends from below the BSR and reaches the...
Citations
... In order to estimate the in-situ stresses, several calculations were carried out with two types of calibrations on them. For the overburden, the density all over the overlying strata (shallow and not available in the logs) was extrapolated using a tie in the mudline [20] and the vertical stress integrates the effects of the water column with a fixed water density [1]. The pore pressure used was calculated from the Sonic Eaton model [21] and the normal pore pressure method [1], these calibrated with Modular Formation Dynamic Tester (MDT) data [22]. ...
This work implements a well-logging approach to evaluate the rock Elastic Parameters, basic Rock Mechanics, and in-situ Stresses in an interval of the Well Poseidon 1 located in the offshore Browse Basin in the Timur Sea of Australia. For this aim, there were used several correlations for the Young’s Modulus, Uniaxial Compressive Strength; one formula for Poisson’s Ratio and one for Angle of Internal Friction, and the Poroelastic Model with tectonic strains for the horizontal stresses with calibrations from logs. All these estimations were compared to a homologous section with triaxial test laboratory data and with previous studies. The results reached indicates that the chosen correlations can replicate under the adequate considerations the values of the rock mechanics and they give also good estimations for in-situ stresses in the interval studied. Moreover, these can be used to model the Young’s Modulus, Uniaxial Compressive Strength, Internal Friction Angle with fair precision. This methodology can be used in order to create geomechanical models by estimating the basic parameters needed, these models can be applied to Improved Oil Recovery, Enhanced Oil Recovery, Carbon Capture and Storage, and Carbon Capture Utilization and Storage projects.
... These geophysical tools test the recordable section sampled rather than the entire rock layer (Bacon et al., 2003). Tying multiple logs together allows a broader assessment of the rock layers (Elmahdy et al., 2018). In this study sonic, resistivity, density, neutron and gamma logs can be used to calculate pore pressure and understand changes within the reservoir (Serra, 1984). ...
Following the decommissioning of the Volve Field located in the North Sea, 200 kilometres offshore Norway, Equinor led joint venture released production and subsurface data for the 14 years of exploration and production on the Theta Vest structure. The four-way Theta Vest structure consists of sandstones from the Jurassic Hugin Formation as the main reservoir, with shales from the Heather and Draupne Formations as a seal. Extensive faulting within the area setup the four-way structural trap (antiform) and migration pathway into the 10 to 70 meters thick Hugin Formation. Three boreholes were studied in conjunction with two seismic surveys taken pre-and postproduction. Pore pressure and hydrocarbon saturation was calculated from logs taken preproduction (15/9-F-12) to study the depletion experienced within the Theta Vest structure when compared to logs taken postproduction (15/9-F-1B and 15/9-F-15A). Pore pressure decreased by approximately 20 bars from pre-to postproduction due to hydrocarbon depletion. A 44% decrease in hydrocarbon saturation was seen from pre-to postproduction, suggesting a 50% recovery rate of the hydrocarbons. Extracted seismic attributes (i.e., amplitude) shows an increase in the far offset angles from 3D to 4D seismic data. An increase in the far offset angles suggests gas exsolution likely took place within the reservoir, causing an increase in amplitudes. Gas exsolution was caused by increased water saturation and a decrease in pore pressure throughout the lifespan of the Theta Vest structure. Following further studies into the feasibility of continuing production, the released gas can be re-injected into the reservoir as a future drive mechanism
... The vertical stress is produced by the weight of the overlying rock layers (Elmahdy et al., 2018;Sen et al., , 2020, it is derived by combining the bulk density log from Eaton (1975) equation: ...
This work aims to determine the present-day in-situ stress and pore pressure in the Ahnet Basin, Algeria, through a 1D geomechanical approach. We investigated the drilling-induced fracture (DIF) from FMI log data to ascertain the direction of maximum horizontal stress (SHmax) from the Ahnet Field. A mean orientation of N140° ( ± 10°) has been interpreted, which is NW-SE (N140°-N320°), with a local variation of ( ± 20°) compared to fields such as Illizi, Hassi Messaoud, and North Algeria, which can be explained by depth variation and intrinsic rock properties. A 1.05 psi/ft gradient of overburden stress (Sv) has been obtained from density. Pore pressure has been estimated from the sonic log by a normal compaction trend, indicates a hydrostatic regime from the surface to the top of the Silurian unit with an average pore pressure gradient of 0.43 psi/ft and an overpressure regime against the hot shale unit with a gradient of 0.58 psi/ft caused by the high in situ temperature in the study area and possible activity of the mega-shear zone. The poroelastic approach under transverse isotropic vertical conditions (VTI) has been used to calculate the minimum and maximum horizontal stress magnitudes. The outlines indicate a high-stress gradient close to 0.82 psi/ft, for Shmin calibrated with MDT stress points and 1.10 psi/ft for SHmax. The stress magnitudes results, suggest a present-day normal to strike-slip stress regime in the Ahnet Basin. Fault reactivation potential at two Silurian units has been inferred from the frictional theory analysis. The results indicate that increased pore pressure in hot shale formations due to by fluid injection and hydraulic fracturing causing shear slippage of the pre-existing faults, resulting in induced seismicity. Our study has contributed to the understanding of stress state origin in Ahnet Basin, the relationship between in situ temperature and pore pressure, and the fault stability analysis in such unconventional reservoir development.
... Given the key role played by compressibility in this model, a major challenge with it is the choice of a proper model for calculating the compressibility. Several researchers proposed empirical equations for predicting pore pressure from seismic data or well logs before drilling (Brahma and Sircar, 2018;Elmahdy et al., 2018;Radwan et al., 2019). The results of these studies showed that the modified Eaton's model may cause an error in the manual selection of the compaction trend line used to discover the normal compaction trend. ...
Accurate prediction of pore pressure (PP) is among the most critical concerns to the design of drilling operation because of the remarkable role of this parameter in preventing particular drilling problems such as wellbore instability, drilling pipe stuck, mud loss, kicks, and even blow outs. Given the limitations of PP measurement through in-hole well tests, a number of analytic and intelligent techniques have been developed to estimate the PP from conventionally available petrophysical logs at offset wells. In this contribution, analytic equations are combined with intelligent algorithms (IAs) in an integrated workflow for estimating the PP. For this purpose, we collected the required data from two wells (herein referred to as Wells A and B) penetrating a carbonate reservoir in two fields in southwestern Iran. The collected data included full-set petrophysical log data at a total of 2850 points as well as 15 measured PPs using the RFT tool. In order to model and validate the results, the data from Well A was used to train the model, with the Well-B data used for validation. Once finished with data collection, a noise attenuation stage was implemented through median filtering. Subsequently, PP estimation was practiced using a couple of popular analytic models, namely modified Eaton's, Bowers', and compressibility models, with the results compared to the measured PPs. Next, a feature selection phase was conducted where depth (Depth), gamma ray log (CGR), density log (RHOB), resistivity log (RT), pore compressibility (Cp), and slowness log (DT) were selected as the most effective parameters for estimating the PP out of the 8 parameters studied at Well A. Feature selection was performed using the second version of nondominated-sorting genetic algorithm (NSGA-II) combined with multilayer perceptron (MLP) neural network (NN). Next, deep learning techniques, simple form of the least square support vector machine (LSSVM) and its hybrid forms with particle swarm optimization (PSO), cuckoo optimization algorithm (COA), and genetic algorithm (GA), and multilayer extreme learning machine (MELM) hybridized with the PSO, COA, and GA were used to estimate the PP based on the data at Well A, with the results then validated using the data at Well B. Results of the training and testing phases showed that, among the 9 models considered in this research, the best results were produced by the CNN model followed by MELM-COA, and LSSVM-COA, corresponding to root-mean-square errors (RMSEs) of 0.1072, 0.1175, and 0.1237 and determination coefficients (R2) of 0.9884, 0.9860, and 0.9844, respectively, indicating the higher accuracy and generalizability of these models compared to other investigated models. Evaluation of these models on the validation data from Well B further remarked the superiority of the CNN model, as per an RMSE and R2 of 0.1066 and 0.9806, respectively. Indeed, the better performance of the CNN model than the other models in both the training and validation phases reflects the high generalizability of this model in the range of the studied data. In general, the good performance of the intelligent models in similar formation along two wells – where the analytic models rather failed to exhibit consistently good performance – proves the superiority of the IAs over conventional analytic models. This methodology is strongly recommended provided more diverse data is available at in larger amounts.
... In unconventional carbonate reservoirs, core measurements show low values of porosity ranging from 0.6% to 39%, and permeability in the range of 0.0009e0.90 mD (Elmahdy et al., 2018;Radwan et al., 2020). The permeability and porosity heterogeneity, pore pressure variations, fracture distribution, and diagenetic evolution of unconventional carbonate reservoirs in the Permian Basin has been established (Dou et al., 2009a(Dou et al., , 2009b(Dou et al., , 2011. ...
The planning and developmental decisions succeeding the discovery of an unconventional oil and gas field is of utmost importance in attaining successful exploitation and production from these tight reservoirs. The development and production of hydrocarbon from these unconventional reservoirs require requires adequate planning and execution which could be challenging, due to the sequence of heterogeneous lithologies of these formations. In this study, we designed and presented a comprehensive field development and production program that is representative of the unconventional oil and gas development in the Central sub-basin of the Permian Basin. To design and achieve optimal field development and production for unconventional reservoirs in the Central sub-basin of the Permian Basin, New Mexico, we utilized field data from an oil and gas well that was drilled to a TVD/MD of 2290 m with a PBTD of 2270 m. Subsequently, we conducted the petrophysical evaluation of the logs and utilized a decline curve analysis for reservoir evaluation of all the members of the formation. We also designed and developed comprehensive drilling, completions, and facilities programs. Lastly, we incorporated an economic analysis of our optimized field development and production design. Our results provide a valuable plan and critical decision-making insight for optimizing field development and production of unconventional reservoirs in the Permian Basin and across the world.
... Stewart (1999 suggested that gas accumulations at shallow depths can cause enough overpressure to form set of faults and fractures with a circular structure. An important observation, however, is that the chalk reservoir of the Apollonia Formation is characterized by its low formation pressure (Elmahdy et al., 2018;Salah et al., 2016) which suggests the releasing of the formation pressure after the generation of the polygonal faults. ...
Interpretations of high resolution 3D seismic data and well logs indicate that the fine-grained carbonates of the middle Eocene Apollonia Formation in the Abu El-Gharadig Basin (Western Desert, Egypt) is deformed by the polygonal fault system. The 3D seismic data cover an area of about 1100 km² including the JDT gas field, where the Apollonia Formation includes gas-bearing reservoir intervals with high porosity and low permeability. The results show that the polygonal faults have no preferred dip or strike directions. They have lengths ranging from 123 to 3800 m, fault throws up to 100m and dips of 27- 88˚. Fault traces are approximately linear in vertical cross-section producing a series of horsts and grabens. We used this data to interpret and geometrically characterize the polygonal faults in a fine-grained carbonate reservoir unit, and we show the faults influence the fluids flow in the reservoir. The increase in the formation pore pressure mechanism is the proposed mechanism for the initiation of the polygonal fault system in the Abu El-Gharadig basin.
... The Apollonia chalk reservoir at the Abu El-Gharadig Basin is considered a commercial, gas-bearing reservoir that drew the attention of several hydrocarbon exploration companies and literatures (Bassiouni et al., 1982;El-Bendary et al., 2016;Elmahdy et al., 2018;Kamel and Nagy, 2014;Marzouk, 2002;Sedek Al Mahdy, 2013;Shamah et al., 1993). During 1970, AMOCO drilled two exploratory wells -WD 7-1 and WD 7-2-as an Apollonia target, but these wells exhibited a noncommercial production (EGPC, 1992). ...
... Sousa and Badri (1996), described the Apollonia Formation chalk as a highly fractured, promising gas-bearing reservoir that requires intensive attention from oil and gas exploration companies. During 2007, Shell drilled the first successful well targeting the Apollonia Formation (Elmahdy et al., 2018). Salah et al. (2016) described the Apollonia chalk reservoir as an unconventional reservoir requiring the application of unconventional techniques (including horizontal drilling and hydraulic fracturing) to unlock the great amount of hydrocarbon entrapped in this formation. ...
... The Apollonia Formation carbonate reservoir is considered an unconventional reservoir with high porosity (approximately 30%) and low permeability (<1 md) (Elmahdy et al., 2018). This chalk reservoir is considered to have good live-source rocks with low formation pressure (Maky and Saad, 2009;Salah et al., 2016). ...
The current work aims to study the structural and facies characterizations of the Apollonia Formation carbonate reservoir by applying the curvature attribute and facies modeling. This reservoir is considered an unconventional, gas-bearing chalk reservoir located at the JDT field in the Abu El-Gharadig Basin, northern Western Desert of Egypt. The workflow begins by computing the curvature seismic attribute on the available 3D seismic data of the field. This is accompanied by the detailed sedimentological and petrophysical analysis of available core data and the distribution of the resulting facies log along the available 3D geological model. The results of the curvature attribute along the Apollonia “A5” layer showed faults traces more than three times the traces determined by the variance attribute along the same layer, with small horizontal spacing between faults about 230 m. This attribute is considered as the best attribute for determining subseismic resolution faults (SSRF) of the polygonal faults affecting the reservoir. The facies analysis indicated that this chalk reservoir is composed of four primary facie: Faceis A (clean chalk), Facies B (slightly argillaceous chalk), Facies C (argillacesou chalk) and Facies D (marl). These facies had been differentiated form each other based on the clay percentage, porosity and permeability. The best reservoir facies are Facies A (clean chalk) with a clay percentage 0 - 5%, average porosity 31% and average permeability 0.43mD and Facies B (slightly argillaceous chalk) with a clay percentages 5-15%, average porosity 23% and average permeability 0.12mD. Distributing these facies along the JDT field declares dramatically that facies characterization of the lower pay zone is better than the upper pay zone because of the abundance of A- and B-type facies along the lower zone. Consequently, a 3D geological model had been constructed which used for the determination of the best location of any further development well targeting primarily A- and B-type facies and for any future production and hydraulic fracturing operations.
The post-snowball Earth world favors the development of hydrocarbon source rock intimately linked to periods of post-glacial marine transgression generating important potential petroleum plays. In the Southern Amazon Craton, hydrocarbons occur in one of the most spectacular examples of post-Marinoan cap carbonate, related to the mid-Ediacaran to Early Cambrian (c. Post 635 Ma) interval associated with the early stabilization of the Gondwana Supercontinent. The Puga cap carbonate consists of the basal portion of the Araras Group exposed in the Araras Alto-Paraguai Basin inserted as a reservoir in an unconventional petroleum system. The cap dolostone overlies diamictites and is overlaid by bituminous limestone and shales (source-rock), and dolostone in the top of a 700 m-thick depositional sequence. The cap dolostone has a diachronic relation with the limestone beds typifying as a secondary reservoir characterized by bitumen-filled fenestral and interpeloidal porosity. The upper dolostone has a closed framework and acts as sealing rocks. This study aims to establish paragenesis sequence and decipher its control on the quality of the cap dolostone as a microbialites-dominated reservoir. Drill core and outcrop samples were analyzed using microfacies, scanning electron microscopy, and cathodoluminescence to unravel the diagenetic history. Aftermath, the Marinoan events favored dolomuds precipitation in the shallow platforms, preserving primary porosity and permeability reduced by early gypsum cementation during oversaturation events. Other destructive processes, such as mechanical and chemical compaction (e.g., stylolite's) and authigenesis of pyrite and low-Mg ferroan calcite cementation, occurred during burial and mesodiagenesis. The low permeability restricts hydrocarbon migration concentrated in the upper cap dolostone, and the early cementation increases the potential for preserving these carbonate deposits. Hydrocarbon maturation was triggered during the burial and uplift of the Araras-Alto Paraguai basin. The cementation phases described here enhance our understanding of the mechanisms behind syndepositional diagenesis in microbially-induced reservoirs. This study uses proxies associated with diagenetic studies to quantify the quality of microbially induced dolostone reservoir linked to the evolution of the Neoproterozoic unconventional petroleum system. In addition, this conception will promote a guide for future exploration and understanding of petroleum plays and suggests a possible Precambrian source rocks component of traditional Phanerozoic Petroleum systems in the central part of Brazil.
Gaseated underbalanced drilling is an attractive choice for horizontal drilling in unconventional reservoirs. However, mud pulse telemetry usually fails in gaseated systems. In this study, an overview of mud pulse telemetry in gaseated drilling was first given for better understanding the current state of the art. Then, factors influencing pulse attenuation in compressible drilling fluids were discussed. Subsequently, a novel method to improve mud pulse telemetry in gaseated drilling were developed. Intermittent gas injection was first developed as a main solution, which refers to pumping only drilling fluids for a while when taking surveys. A model for determining the optimal duration for stopping the gas injection was also proposed, which is critical and must be optimized to allow both telemetry use and underbalance. As another sub method, a gas–liquid mixer was designed to overcome the nonuniform mixing phenomenon in the standpipe, which is also a potential factor in telemetry failure. Flow restrictor and lowering operating frequencies as the other two sub methods were also recommended. Finally, case studies and efficacy analysis were conducted to evaluate these sub–methods. The method of intermittent gas injection was applied in one case. The maximum gas injection rate allowed by acceptable telemetry was raised from 6 m³ min⁻¹ to 12 m³ min⁻¹, which demonstrates the feasibility of the method. Another case showed that the gas–liquid mixer enhanced the detected signal amplitude from 0.0033 MPa to 0.01 MPa, which obtained successful decoding. The results also show that the continuous wave mud pulse telemetry tool has more advantages than the positive pulse systems for mud telemetry in gaseated drilling. The results of efficacy analysis show that flow restrictor and lowering operating frequencies also can enhance mud pulse telemetry performance in gaseated drilling.
