hydrocarbon

Simultaneous in-reservoir upgrading and recovery of heavy oil are experimentally studied by using a continuous setup filled with carbonate cores. Upgrading reaction products as well as the recovered oil are analyzed in order to investigate the recovery mechanisms associated with this process.

In-situ upgrading technology (ISUT) is based on injection of high molecular weight (low quality) cut of oil, e.g., vacuum residue (VR), together with ultradispersed nano-catalyst and hydrogen. By injecting VR, catalyst, and hydrogen, the catalytic nano-particles deposit in the rock around an injection well, where the upgrading reactions occur. In this study, first, upgrading reactions happen inside a core packed container at the temperature, pressure, and residence time of 360 °C, 10 MPa, and 36 h, respectively. Subsequently, the hot reaction products are directed into another cylinder filled with carbonate cores to displace the heavy oil in place.

There are two main steps in a reservoir during ISUT. First, the injected VR is converted to lighter products during hydroprocessing reactions. Then the upgraded liquid and gaseous products along with hydrogen will displace the heavy oil toward production wells. At the conditions of this experiment in the reactor, 47 wt% of the VR cut is converted to lighter products with 1 wt% gases (mainly H₂S and hydrocarbons with 1 to 5 carbon atoms) and 5.4 wt% naphtha cut (hydrocarbons with 5 to 12 carbon atoms). These light products act as solvents in the areas farther from the reaction zone and enhance the recovery of heavy oil. In addition, high temperatures, mechanical push, and rock matrix thermal expansion improve the oil displacement in the carbonate rock.

By enhancing the oil recovery and permanently upgrading heavy oil in one single stage, the need for diluent addition and steam generation is minimized, which makes ISUT economical and environmentally favorable. In an innovative experimental setup, both upgrading and recovery steps in the ISUT process are carefully analyzed.

The wettability of reservoir rocks impacts many aspects of well planning and production, from estimating hydrocarbon saturation to enhanced oil recovery. Wettability is often experimentally quantified through laboratory measurements; however, in-situ wettability assessment is challenging. In this work, we introduce a new method to quantify wettability using resistivity measurements obtained from either well logs or core measurements. The objectives of this paper are (i) to introduce a resistivity-based wettability index from our recent analytically-derived resistivity model that takes into account wettability and (ii) to verify the reliability of the new resistivity-based wettability index using Amott Index, U.S. Bureau of Mines (USBM), and/or contact angle wettability measurements as reference.

We quantify the resistivity-based wettability index using our new analytically-derived resistivity model which requires as inputs the resistivity of the rock-fluid system and brine, water saturation, porosity, and pore-geometry-related parameters. Water saturation and porosity can be estimated from the interpretation of borehole geophysical or core measurements. The pore-geometry-related parameters can be estimated from image analysis performed on three-dimensional pore-scale images (e.g. micro-computed tomography) or through a physics-based calibration method. Next, we calculate the resistivity-based wettability index by minimizing the error between the measured and predicted resistivity of the rock-fluid system. To verify this method, we prepare core samples covering a wide range of wettability states and saturation levels. We vary the wettability of the samples by injecting brine, an anionic surfactant solution, or a naphthenic acid and decane solution to make the core samples water-, mixed-, or oil-wet, respectively. Finally, we obtain the resistivity-based wettability index in the core samples and verify its reliability by comparing the estimates against the Amott Index and the contact angle measurements. We also used previously documented data in Berea sandstone for further verification of the new method.

We successfully demonstrated the reliability of the introduced resistivity-based wettability index for limestone and sandstone core samples. The resistivity-based wettability indices were in agreement with both Amott and USBM Indices for the limestone and sandstone samples, respectively. The average absolute difference between the resistivity-based wettability index and the Amott and USBM Indices was less than 0.4 for all the core samples documented in this paper. The outcomes of this work can potentially be used for assessment of wettability from borehole geophysical measurements, to deliver in-situ properties of rocks in real-time. Additionally, the new resistivity model consists only of physically meaningful parameters and minimizes calibration efforts. Furthermore, if the wettability, porosity, and pore-geometry-related parameters are known, then we can use this resistivity model to obtain water saturation without the need for calibration.

Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) reckons on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability and hydrocarbon saturation still rely on model calibration using core measurements. Furthermore, assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include (a) developing a new multiphysics workflow to simultaneously quantify rock fabric features (e.g., porosity, tortuosity, and effective throat size) and hydrocarbon saturation from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements, (b) introducing rock physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure, and (c) validating the reliability of the new workflow in pore- and core-scale domains.

To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid substitution algorithm to estimate the T₂ distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T₂-distribution for assessment of porosity, pore-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from interpretation of resistivity measurements. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in core- and pore-scale domains on rock samples at different water saturation levels.

The introduced multiphysics workflow provides accurate description of the pore structure and fluid distribution in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. Finally, since the new workflow relies on fundamental rock physics principles, hydrocarbon saturation, permeability, and saturation-dependent capillary pressure can be estimated from well-logs with minimum calibration efforts, which is another unique contribution of this work.

This paper presents a two-way coupled modelling approach to simulate CO₂ movement and containment with geochemical reactions and geomechanical effects. CO₂ storage simulation studies cover three main disciplines, reservoir engineering, geochemistry and geomechanics. This new approach of coupled modelling simulation, by simultaneously simulate both effects of geochemistry and geomechanics, is considered as a more representative and better predictive modelling practice.

The integration of geochemistry and geomechanics effects is important for CO₂ sequestration modelling. There are a number of published studies on coupled modelling for CO₂ storage. However, the majority of the studies has only covered dynamic-geomechanics or dynamic-geochemistry interaction, without considering any direct geomechanics-geochemistry interaction in a reservoir condition. It is crucial to understand the integrated effects when injected CO₂ dissolves into formation water and interacts with formation rock. Depending on in-situ conditions, the formation water with dissolved CO₂ could weak or strengthen the formation stress due to geochemical reactions of formation minerals. Therefore, coupled modelling is needed to ensure the long-term safety of CO₂ containment at a CO₂ storage site with the interactions among geomechanical, geochemical and dynamic fluid flow, and especially to understand the slow and not experimentally accessible mineral reactions.

In this paper, a high CO₂ content gas field in Malaysia with high temperature (150°C) and high pressure (350 bar) has been studied using integrated coupled modelling approach. The simulation input parameters are first investigated and collected from literature and laboratory studies. A two-way coupled modelling simulation with the consideration of geochemistry and geomechanics effects is desirable because it allows the updates of reservoir properties back and forth in every time step. Different CO₂ trapping mechanisms, long term fate analysis, subsidence and heaving analysis, and changes of porosity and permeability are investigated. The time frame of simulation studies consists of CO₂ injection period (15 years) and post CO₂ injection period (500 years).

During the first 15 years of CO₂ injection, 95.13% of injected CO₂ is structurally trapped, 3.67% of CO₂ is soluted in formation water and 1.2% is trapped by mineralization. About 0.041m of heaving is observed at the injection area while about 0.05m of subsidence is observed at the production area. In the investigation of long-term CO₂ fate, it is observed that CO₂ gas will be trapped between the lighter hydrocarbon gas layer and aquifer due to density difference.

More than a half of world's hydrocarbon reserves is presented in carbonate reservoirs. Conventional waterflooding leads to inefficient oil recovery from these reservoirs, because majority of them have mixed or oil-wet wetting properties. It is well documented in literature, that the main reason of oil wetness of carbonate rocks is adsorbed components from crude oil. Although progress has been made in determination of oil components, which have a tendency to react with carbonates, carbonate reservoirs development still remains challenging. Hence, in this study we investigated the distribution of adsorbed oil components on rock surfaces in order to define their influence on fluids flow through porous carbonate samples. This work presents the results for several carbonate core samples taken from the oil zone of an oil reservoir, which mostly consist of calcite with the small impurities of magnesite and quartz. The work provides the standard study of pore structure of samples to assess the solvents influence on pore network of samples using μCT; the method of evaluation of the amount of organic matter adsorbed on calcite using Rock - Eval pyrolysis; the visualization of such matter distribution through samples; and also the results of kinetics experiments in order to evaluate the bond disruption energy between organic matter and surface. Studies have shown that combination of pyrolysis and μCT provides comprehensive and improved data about organic matter.

Carlos Pérez Garcia, Ecuador’s Minister of Hydrocarbons, discussed the direction of his country’s upstream oil development effort in a recent interview with JPT. In a talk to SPE’s Gulf Coast Section International Interest Group, Ecuador’s Minister of Hydrocarbons outlined his country’s push to attract international oil and gas investment.

Passive fire protection (PFP) has been used as a method to avoid/delay global collapse of offshore installations. Location of PFP is often based on simplistic assumptions, standards, guidance, and methods that do not always consider the real response of the structure to fire. The energy contained in oil and gas makes them immensely useful—and dangerous. A fire fueled by hydrocarbons can quickly threaten anything exposed to it. Building in passive fire protection when constructing facilities is wise practice.

This study presents an overview of the structural response and failure mechanism of three-sided protected beams and proposes design solutions. Passive fire protection (PFP) has been used as a method to avoid/delay global collapse of offshore installations. Location of PFP is often based on simplistic assumptions, standards, guidance, and methods that do not always consider the real response of the structure to fire. The energy contained in oil and gas makes them immensely useful—and dangerous. A fire fueled by hydrocarbons can quickly threaten anything exposed to it.

Applying sufficient passive fire protection (PFP) on topside structural-steel members is critical. Simplified and conservative approaches are available to estimate the extent and amount of PFP necessary. This study presents an overview of the structural response and failure mechanism of three-sided protected beams and proposes design solutions. Passive fire protection (PFP) has been used as a method to avoid/delay global collapse of offshore installations. Location of PFP is often based on simplistic assumptions, standards, guidance, and methods that do not always consider the real response of the structure to fire.

Leading voices in the oil and gas industry looked at key market changes, the regulatory and political climate, and potential business model disruptors in a wide-ranging panel discussion at the recent Houston Energy Breakfast. Following years of deliberation, the European Union (EU) released a recommendation on unconventional hydrocarbons and a related communication in 2014. This paper traces the origins and development of these documents, which provide vital clues for the road ahead in European shale-gas regulation. Well plugging and abandoning on a limited budget is a lofty goal that forces the industry to consider new ways and new materials. Cost-effectively dealing with this global problem will require developing tools to carry out the decommissioning without bringing in a drilling rig.