The rapid growth of the Amazon deep-sea fan following the Andean uplift led to its gravitational collapse, forming upstream extensional domains and downstream thrust belts. The Amazon fan consists of two compartments with significant structural differences: one thick and extended compartment in the Northwest (NW), and a thinner and more restricted compartment in the Southeast (SE). This study examines whether these different structural geometries can be attributed to spatial and temporal variations in overpressure generation mechanisms, using petroleum systems analysis techniques. We first show that over the last 8Ma, overpressure gradually increased in the fan and deformation and overpressure migrated basinward along the detachment surface for both compartments. However, overpressure mechanisms differed significantly between the two compartments. In the SE, disequilibrium compaction driven by high rates of sedimentary input from the Amazon River, appears to be the primary mechanism of overpressure, while in the NW, thermogenic gas generation and smectite-to-illite transformation are the main overpressure generation mechanisms. Finally, we discuss how, in addition to variations in sedimentation rates over time, the differing timing of thermogenic gas generation and/or the role of these hydrocarbons as an overpressure mechanism could be linked to the thermal history of the Foz do Amazonas basin, and thus to its structural heritage, in particular the nature of the basin substratum on a segmented margin.

ABSTRACT In well construction, well stability is needed to predict drilling time, costs, and risk management accurately. Several models have been developed in the last 60 years to estimate rock parameters and stress magnitudes from well logs. However, this involves uncertainties due to rock heterogeneity, lack of information due to high data acquisition costs, and indirect measurements. Drilling monitoring has been used to mitigate instability occurrences by updating the geomechanics model while drilling. Nevertheless, monitoring highly depends on the analyst's experience and immediate interpretation of available information. Artificial Intelligence algorithms have been used to improve efficiency in many different technologies, but they depend on good predictions to learn from experience. In order to build an accurate and generalist ANN model, this paper uses the real case study experience of the analysis of offshore wells in Brazil calibrated with drilling events. Data is provided by the Brazilian National Petroleum Agency (ANP) and used to build an ANN model. The available drilling parameters are used, such as weight on bit, torque, rate of penetration, log data and well reports. Neural networks were applied to the available data to build a model. Model output includes pore pressure and collapse pressure for the survey. The proposed model can be an additional tool to help well construction operations. INTRODUCTION The maximum value of pore or collapse pressure defines the lower boundary of the drilling mud window. Using mud weights below those values can lead to several problems, such as inflows, excess reaming, poor hole cleaning conditions, excess cavings, pack-offs, stuck pipe, and more severe issues, such as loss of the hole or uncontrolled blowouts. Methods to estimate pore pressure, in-situ stresses, and collapse curves were developed and improved over many years (Barton et al., 1997a; Eaton, 1972, 1975a, 1976; Fjaer et al., 1992; Zoback et al., 1985; Zoback, 2007). Most pore pressure methods are applied to argillaceous rocks assuming under-compaction mechanisms (Vernik, 2016). Pore pressure in permeable environments is generally measured using well pressure tests or inflow events.

Summary This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.

The detailed study of competitive adsorption of methane (CH4) and carbon dioxide (CO2) is essential for enhanced gas recovery and carbon dioxide sequestration operations. In this study, the adsorption of methane and carbon dioxide isotherms was measured at 25oC, 45oC, and 65oC at pressure up to 100 bar for overmature carbonaceous shales of Sungai Perlis beds, Peninsular Malaysia, with TOC ranges between 5.48 wt % to 11.33 wt%. There is no study reported on the competitive adsorption in these shales to date. Furthermore, these shales have never been analyzed for the estimation of carbon storage potential and pore size distribution. Therefore, the current study investigates the competitive adsorption behavior and carbon storage potential using a volumetric approach as well as the pore structure and its relationship with adsorption potential of shale. The mineralogy and organic contents were analyzed using X-ray diffraction (XRD) and TOC analyzer. The pore structure was analyzed using low pressure nitrogen adsorption mercury intrusion capillary pressure (MICP) and filed emission scanning electron microscopy (FESEM). The total carbon storage capacity of shale was estimated using the volumetric approach proposed by US-DOE on regional scale. The results indicated that the measured maximum excess adsorption potential of CH4 ranges between 0.019 mmol/g to 0.051 mmol/g, whereas the maximum excess adsorption potential of CO2 ranges between 0.026 mmol/g to 0.24 mmol/g. Both the supercritical Dubinin–Radushkevich (SDR) and Langmuir model best fit the experimental data for CH4. Whereas Dubinin–Langmuir k model (DLK) and Langmuir model best fit the experimental data for CO2. In comparison, the DLK model is considered best for subcritical CO2 adsorption. The accuracy of the isotherm models was evaluated using the error analysis technique, which indicates satisfactory performance. The studied samples indicate the presence of micropores, mesopores and macropores, the pores are open and permeable i.e., slit like and wedge shaped. The MICP indicate the presence of bimodal pore throat size distribution. The fractal properties of pore ranges between 2.29 to 2.69, which indicate the complex pore internal structure. Furthermore, there is a higher affinity to CO2 than CH4 under similar conditions of temperature and pressure. The adsorption ratio/selectivity ratio of CO2 over CH4 ranges between 0.56-11.24, which makes the shale the best target for carbon storage operations. The total carbon storage potential ranges between 0.48 to 1.75 Gt. The adsorption ratio increases with an increase in organic contents; however, clay minerals are not affecting significantly. The adsorption ratio decreased initially with increased pressure and then stable with increasing pressure, suggesting that reservoir pressure should be lower before the injection of CO2 into the reservoir. The adsorption volume increase with an increase in specific surface area and micropore volume. This study provides the basis for the estimation of carbon sequestration and enhances gas recovery.

Permeability is one of the main petrophysical parameters to determine the potential for production of oil and gas from a reservoir. The wireline or logging-while-drilling (LWD) for in-situ permeability measurements is a challenge in carbonate reservoirs due to the complexity attributed to deposit environment, diagenetic history, dissolution and heterogeneous pore size distribution and connectivity. Several mathematical models have been proposed to estimate permeability from log data. However, the results from these models in carbonate rocks are sometimes inaccurate, so, alternative mathematical models are necessary to obtain more reliable results.

Reliable estimates of porosity can be obtained from different types of geophysical well logs. However, obtaining in situ permeability estimates is still a major challenge in the geosciences. This work aims to evaluate the application of data mining techniques to NMR logs for rock permeability classification, thus far tested only on laboratory data. For this study, we used a petrophysical database from two Brazilian Pre-salt wells located in the Santos Basin, a formation notoriously difficult to characterize, mainly due to its diversity and complexity. Six classification algorithms were evaluated (k-NN, NB, C4.5, RF, SMO, and MLP) according to their ability to estimate the permeability of rocks in four distinct classes (low: <1 mD, intermediate: 1–10 mD, high: 10–100 mD, and excellent: >100 mD). The predictive performance of the algorithms was compared to the behavior of two traditional permeability estimators. With an accuracy of 66%, the Naïve Bayes algorithm, combined with two preprocessing steps – unsupervised discretization and attribute selection – achieved the highest predictive performance. That mark surpassed the accuracy obtained by Kenyon and Timur-Coates estimators by 154% and 106%, respectively, providing evidence for the superiority of the data mining technique to recognize permeability classes based on NMR logs. Classification experiments employing NMR logs in conjunction with conventional logs were also conducted, but this log combination was not able to best the predictive result based solely on the NMR log data.

在新西兰,东海岸盆地是主要页岩油气区,广泛分布着Whangai组储层.该地层易生油气,在东海岸盆地的大部分地区普遍存在,通常由上Calcareous、Porangahau和Rakauroa段组成.这项研究的主要目的 是开发一种综合方法,以确定页岩储层最佳增产改造层段.作者评估了Rakauroa段脆性指标的四种不同定义,在3口研究井中只钻了Rakauroa段.为此专门开发了一个基于Python的自动化处理方法,该方法使用四个指标:弹性参数、内部摩擦系数、矿物学参数和总有机碳含量.通过这一过程,将这四个指标进行了分析组合,以选择脆性值最高的层段,并确定了产层中的最佳增产层段和最理想的射孔层段.作者的研究结果表明,Whangai组的粘土含量为25％(在某些层段内粘土含量达到70％),最大有机物含量为2.54％.地质力学模型表明高孔隙压力在整个储层段内分布均匀.位于沿海区块的Opoutama-1井在1497-1750 m之间的层段表现出较高的综合脆性指数,从增产角度看,表明具有出色的特性.

Within New Zealand, the East Coast Basin represents the primary shale oil and gas play in which the Whangai Formation is widespread. This formation is oil and gas prone and prevalent throughout a large area of the East Coast Basin and is typically composed of the Upper Calcareous, Porangahau, and Rakauroa Members. The primary goal of this study was to develop an integrated methodology to define the best stimulation intervals in the formation. To do this, we evaluated four different definitions of the brittleness index for the Rakauroa Member, the only member drilled in the three study wells. A Python-based automated process was specifically developed for this purpose and uses four indexes: elastic parameters, internal friction coefficient, mineralogy, and total organic carbon content. Through this process, these four indexes were analytically combined to select intervals with the highest brittleness values and identify the optimum stimulation interval and most desirable perforation intervals in the pay zone. Our results show that the Whangai Formation contains 25% clay (and reaching up to 70% clay content in some intervals) and a maximum organic matter content of 2.54%. The geomechanical model indicates a uniform distribution of high pore pressure across the entire reservoir section. The interval between 1497 and 1750 m in the Opoutama-1 well located in the Coastal block presents high combined brittleness indexes, indicating excellent characteristics from a stimulation standpoint.

In this work, we characterized mineralogical, petrographic and petrophysically the Mupe Member from the Purbeck Group lower portion, located in southern England and northern France.These rocks mainly consist of limestones and can be considered as a partial analogue rock of the Brazilian pre-salt carbonate reservoirs.The laboratory tests campaign to characterize there lithologies comprised of X-ray diffraction (XRD) tests and thin sections description, gas effective porosity and absolute permeability, nuclear magnetic resonance (NMR).The results of XRD and thin sections indicated a mineralogy rich in low-magnesium calcite and the presence of different types of pores.The NMR T2 distribution indicated that the plugs are very heterogeneous, having pore size distributions varying from bimodal to polymodal.

Shale ‘stability’ has been extensively studied the past few decades in an attempt to understand wellbore instability problems encountered while drilling. Drilling through shale is almost inevitable, it makes up 75 percent of sedimentary rocks. Shale tends to be characterized as having high in-situ stresses, fissile, laminated, with low permeability. However, not all shale are the same, and the problem herein lies where they are all treated as such, in which most cases, has shown to be ineffective. Ironically, shale is predominantly generalized as being "reactive/swelling". Even though this can be true, it is not always the case because not all shale is reactive! In reality, there are many different types of shale: ductile, brittle, carbonaceous, argillaceous, flysch, dispersive, kaolinitic, micro-fractured etc. This study aims to clear many misconceptions and define different types of shale (global case scenarios) and their failing mechanisms that lead to wellbore instability, formation damage and high drilling cost. Afterwards, solutions will be offered, from a filed operation perspective, which will provide guidelines for stabilizing various shale based on their failure mechanism. Furthermore, we will define the symptoms for shale instability and propose industry accepted remedies.

Abstract This paper describes the test protocols and procedures of RCX Straddle Packer Microfrac for the estimation of formation Breakdown, fracture propagation and fracture closure pressure at different levels in Vaca Muerta formation. As a result, the horizontal stress field can be estimated, which in turns allows to infer if the fracture scheme and productivity agree well with initial prognosis. Historically, this tool had been used for the estimation of formation pressure and fluid samples for unconsolidated formations. However, a micro-fracture job, pump capacity, packer hermeticity and a well design test protocol were the key to allow get formation breakdown, fracture propagation, fracture closure through pumping flow back and fracture reopening in various cycles. Such procedure was performed at two depths with success. Selection of the test intervals involved a preliminary geomechanical model for the determination of stress conditions, mechanical properties and wellbore stability analysis to choose proper mud density to reduce the probability of well damage (breakouts mainly), which can compromise test hermeticity. Then, after drilling, well logs including wellbore image and caliper analysis enable the determination of test intervals with minimum damage. In the test well, Microfrac tests were performed successfully on two intervals out of four selected. Interpretation allowed the estimation of closure pressure related to minimum horizontal stress. Moreover, a rough estimation of maximum horizontal stress, based on breakdown pressure and closure pressure was performed as well. Such results agree well with the initial geomechanical model. Strike slip regime was confirmed in such a way that no alarms were set for future development through horizontal wells. But it is necessary to make a deepper investigation to ensure a favorable anisotrophy stress ratio. Some areas with unfavorable vertical to horizontal stress ratio, have been show low performance productivity. The main advantages of this type of tests are: (i) the availability to acquire information through several depths in a vertical well. (ii) Tests were performed in open hole conditions. (iii) Horizontal in situ stresses can be estimated. (iv) Time efficiency in comparison with classical DFIT tests. (v) Calibration of geomechanical model for future development. Through the application of this tool, a new methodology was set, which allows for an early diagnose of the horizontal stress field leading to the determination of stress regime. Therefore, if the worst-case scenario appears related to inverse stress regime, development plans can be reorganized, reducing potential economic losses, considering that, as had been demonstrated in Argentina, horizontal wells placed on inverse regime led to EUR lower than breakeven.

The Amazon Fan provides a natural laboratory to study the generation of overpressure, due to rapid late Cenozoic burial that has resulted in gravitational collapse above shale detachments. Here we examine collapse systems for the first time using the techniques of petroleum systems analysis. We propose an integrated methodology based on numerical modeling constrained by the structural restoration of a seismic profile across the southwestern fan. The results provide information on the evolution of pore pressure and temperature and their implications for the operation of the detachment and overlying extensional and compressional faults during the deposition of up to 6 km of sediment over the last 8 Ma. The modelled thermal history implies that fluid release by smectite-to-illite transformation has taken place within the thickening sedimentary succession, but has not significantly contributed to pore pressures along the detachment. Modeling of hydrocarbon generation and migration from source rocks beneath the fan indicates gas accumulated in successions at depths of 102-103 m beneath the detachment without influencing pore pressures along it. In contrast, model results indicate that overpressures have varied in response to disequilibrium compaction. Fault activity within the collapse system took place during phases of higher sedimentation rates, and ceased from 5.5 to 3.7 Ma when sediment supply to the SE fan decreased. From 2 Ma, renewed sediment flux and shelf-slope progradation led to a basinward migration both of overpressure along the detachment and of fault activity above it. We conclude that gravity tectonics in the Amazon Fan over the last 8 Ma have been mainly controlled by overpressures due to disequilibrium compaction, with secondary contributions from clay mineral transformation. Present-day pressure conditions show that the southeastern Amazon Fan is not at equilibrium and gravity driven deformation could occur at any time.

Venezuela’s largest heavy-oil deposits are found primarily in the Faja del Orinoco Belt. These deposits exhibit a low production rate under the cold flow method. The objective of this study is to model the impact of steam injection on the fluid dynamics, geomechanics, and seismic attributes for the Faja del Orinoco steam-assisted gravity drainage pilot project. In order to make core testing more representative under this operation conditions, a new heating system was developed to execute triaxial tests with heavy oil samples under elevated temperature and the results were used as input in a new thermo-poro-elastic–plastic coupled fluid flow and geomechanics simulator. Our simulation show that, after 8 years of steam injection, the temperature increased, reaching 280 °C around the injection well. In addition, oil saturation decreased from 0.803 to 0.13, pore pressures dropped to approximately 8.68 MPa, and the volumetric strain changes reached 0.00078 close to injector well. The results also indicated that the effects of compressibility on cumulate oil production with thermo-hydro-mechanical coupling reached 35% more than without coupling in 8 years of steam stimulation. The cumulative steam-oil rate was approximately 2.70 for 100 tons of steam per day, with 0.203 × 106 m3 (1.28 mmstb) cumulative oil volume and 0.548 × 106 m3.

Understanding a naturally fractured rock network is a challenge. Understanding granitic and volcanic petrophysics is another challenge. Consequently, a fractured reservoir in a basement rocks is a double challenge. The Guanaco Field is in the Neuquén province, West Argentina. Its “wet or dry” gas production comes from basement rocks. Fractures that are present in these rocks allow the storage and permeability to fluid flows, but the fracture intensity is highly variable. For this reason, productivity is highly variable from one well to another. This heterogeneity is also noticeable along the section of vertical wells. Consequently, completions must be selective. Detailed formation evaluation is the key for a successful completion. This paper describes a case study that integrates data from mudlogging, open hole logs and a 3D static model to design a completion strategy. Borehole imaging logs (from wireline resistivity and acoustic) are the main technologies to characterize the fracture network. This data integration enabled selection of the best potential intervals to perforate and stimulate. Although these are naturally fractured reservoirs, a hydraulic fracture must be performed to start production. Well testing and production logging confirm the results of this methodology.