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The heavy oil reservoirs are currently mainly targeted by thermal enhanced oil recovery technologies, particularly, steam flooding. Steam flooding is carried out by introducing heat into the reservoir to unlock the recovery of heavy oil by reducing oil viscosity. Several investigations were carried out to improve oil recovery by steam flooding. Most recently, high steam flooding is reported as an effective approach to improve recovery in high pressure heavy oil reservoirs. The oil recovery from steam flooding is substantially affected by the steam quality and injection temperature. In this study, an attempt was made to look into the integration of parameters, i.e. steam quality and injection temperature upon steam flooding on oil recovery by using a simulation approach via ECLIPSE. The results obtained indicated that high temperature along with the moderate value of steam quality gives the best result regarding oil recovery for steam flooding in an economical way.

It is essential to characterize fluid flow in porous media to have a better understanding of petrophysical properties. Many approaches were developed to determine reservoir permeability among which the integrated analysis of hydraulic flow unit (HFU) and electrofacies (EF) is considered to be useful one. However, the application of HFU and EF analysis has not been totally understood with a limited data to develop correlation for less distance offset wells. In this study, an attempt was made to show the application of integrating HFU and EF for reliable estimation of permeability using core and wireline log data in one of the gas fields in Pakistan. The results obtained indicate that the integrated approach proposed in this study can be used, especially in less distance offset wells when a limited number of data are available for petrophysical characterization.

Many parameters have been indicated crucial for the selection of a saline aquifer as a carbon dioxide (CO2) storage site. However, less attention has been given to the impact of heterogeneity on the performance of these storage media. Thus, the heterogeneity effect was evaluated in this paper by adopting a numerical modeling approach and the existing screening criterion developed for the aquifers was updated. The updated criterion for CO2 storage purpose would enhance the confidence level during the selection of deep saline aquifer and thus, help to address the climate change issue. The numerical modeling was carried out via CO2STORE module of Eclipse300 Simulator to evaluate the effect of different levels of heterogeneity on CO2 storage potential. Different degrees of heterogeneity from homogenous systems to highly heterogeneous systems in the model were incorporated through the Lorenz coefficient. In this way, simulation of nine cases was carried out for three different aquifers with different porosity values. A comparison of these results showed that heterogeneity causes the aquifer to have lower storage capacity. On the trapping potential, dissolution trapping was significant and the amount of free gas in all cases was minimum. In addition, the aquifer with the highest level of heterogeneity (HLH) had a minimum fraction of residual trapping regardless of porosity. It was also found that final pressure at the end of 30 years is the same and high for low-level heterogeneity (LLH) and medium level heterogeneity (MLH) cases and low for HLH, while the injection rate stability duration is least for HLH and maximum for LLH. Based on the results obtained, it can be concluded that low to medium level heterogeneous aquifers with a good porosity can be a suitable choice for CO2 storage.

Detailed structural analysis of an onshore field was carried out to study the geometry and interactions of the interpreted normal faults. The faults have E-W strike and are dipping towards the south. Majority of the faults are coherently linked with only a few displaying isolated growth model. Throw generally increases with increasing depth. The distribution of the throw on the fault planes shows different geometries ranging from symmetrical with steep gradients at the fault tips and displacement maxima at the center to asymmetrical with steep gradient at one tip. Faults interacted by way of splay and systematically formed relay ramp structures. At depth, splay display isolated fault profile rather than a maxima at the intersections suggesting an unusual interaction at intersection between major fault and splay with low displacement at intersection.

Climate change is taking place due to significant emissions of greenhouse gases into the atmosphere. CO2 storage in geological formations is a promising approach that can help to reduce greenhouse gas emissions from large emitters such as the steel and cement industries. However, effective storage in underground formations requires active trapping mechanisms to reduce the likelihood of leakage. Carbon mineralization is a trapping technique that can permanently store CO2 in reactive rocks such as basalt. Although this method has been known for a long time, only two pilot projects in Iceland and the USA practiced CO2 injection into basalts. This could be mainly due to the complexity of the interactions, the rapid carbon mineralization, and the difficulty to estimate the storage capacity in the long term. In this paper, we discuss different mechanisms and technical challenges of CO2 storage in igneous rocks and propose a selection criterion based on laboratory and field-scale experience. It appears that basalt is a suitable rock for rapid carbon mineralization given its worldwide distribution, vesicular texture, and favourable mineral composition, but the lack of effective monitoring techniques and the amount of water required for injection are two major challenges that need to be addressed.

There have been interests to link different cuttings/cavings to various wellbore failure types during drilling. This concept is essential when caliper and image logs are not available. Identification of wellbore failure during drilling gives more chance of immediate actions before wireline logging program. In this paper, an approach was presented based on the image processing of ditch cuttings. This approach uses the sphericity and roundness of cuttings as input data to classify caving types and subsequently determine the dominant failure type. Likewise, common definitions of cavings were discussed initially before a new criterion is suggested. This quantitative criterion was examined by observations from caliper and acoustic image logs as well. The proposed approach and criterion were implemented on ditch cuttings taken from a well in Western Australia. Results indicate that the primary failure is shear failure (breakout) due to high levels of angular cavings. However, another failure due to the fluid invasion into pre-existing fractures was also recorded by blocky cavings. Keywords: Caving shape, Cuttings, Drilling, Image analysis, Wellbore failures, Roundness, Sphericity

Drilling into presalt formations has been a long-standing issue due to the rapid changes in the diameter of the borehole during drilling operations either because of creep or wash-out dissolution. There have been many studies on characterization of salts, with many mathematical models being presented to estimate the pressure induced due to the squeezing salt sheets. However, the results of none of these models have been fully validated against real field data and some recommendations have been made based on numerical simulations. In this study, attempts were made to introduce a methodology based on damage mechanics for wellbore stability analysis of a wells drilled in the southern part of Iran. The results obtained indicated that the presence of a thick salt layer in the well has resulted in significant wellbore closure in the intervals above the reservoir section. It was also found that the salt exhibits viscoelastic behaviour during drilling due to the homogeneous temperature which has not reached the threshold limit of viscoplastic boundary. A complicated change in the stress regime was also observed which could be linked to the existence of the thick salt layer or presences of a fault crossing the well. Therefore, it is recommended to further validate this model in other wells using the methodology presented.

In recent years, natural surfactants have been considered as part of the EOR processes given their non-toxic and environment friendly nature. However, once chosen wisely, surfactants can only reduce the interfacial tension (IFT) and are often unable to alter the surface wettability for a better hydrocarbon production. Low salinity water (LSW) is a good candidate on these occasions, but the interaction of LSW with natural surfactants for wettability alteration has not been deeply understood. In this work, an attempt was made to extract and characterize a natural surfactant which could be used together with LSW for EOR purposes. To do this, a natural surfactant was extracted from Saponin and its physico-chemical properties such as CMC, foamability, and thermal stability were tested. A series of IFT and wettability measurements were then conducted to evaluate the performance of the surfactant as an EOR additive. The results obtained indicated that the extracted surfactant has a high thermal stability and can be fully functional in the temperature of up to 100 °C. It appears that increasing the level of salinity in the solution can improve the efficiency and foamability of the surfactant. It was observed that the extracted surfactant as can reduce the IFT of an air-water system by 78.65% and is capable of favorably altering the surface wettability of sandstone for a better hydrocarbon production once combined with LSW.

Carbon Capture and Storage (CCS) has been widely recognized as an effective strategy that may significantly contribute to achieving the net zero emission target by 2050. There are currently more than 50 CCS injection and pilot sites around the globe that may require a long-term integrity assessment to avoid leakages or contamination of subsurface resources. The major concern here is the complex interactions of CO2 with rocks and other sealing materials (cement) that can be accelerated by pressure and temperature conditions. In this paper, we review different mechanisms that may lead to the generation of leakage paths in CO2 geological sites and attempt to provide a risk assessment scheme that may improve the safety of injection and storage operations. It seems that the results reported from the laboratory experiments are still inconclusive and not comparable with the field observations. This could be due to the limited duration of the tests conducted, complexity of mechanisms involved and the slow reaction rates of many chemical processes in a CO2 storage site. Geochemical reactions, pressure and temperature are the main parameters that can potentially induce leakages from different geological sites, but a poor cement job is perhaps the main reason behind the leakage of CO2 from the near wellbore region during injection and storage.

Shale formations are known for their chemical interactions with water based muds which may result in swelling, bit balling or even closure of the wellbore. As a result, eco-friendly water based fluids with inhibitive characteristics are required for drilling through shale formations. The aim of this study is to provide a deeper insight into drilling through shale formations by providing few approaches for different circumstances. Many inhibitors developed so far are introduced with their mechanism of shale inhibition presented. It appears that silicate based muds and thermally activated mud emulsion (TAME) are the best option to mitigate shale related issues, but more studies are required to provide a permanent solution for this very complicated issue, especially under HPHT conditions.

The influence of Supercritical CO2 (SCCO2) on geochemical interaction is considered a key factor affecting CO2 storage capacity in shales. To address this issue, samples from Eagle Ford and Mancos shales were treated with SCCO2 for 30 days at 70 °C and 18 MPa. Analytical methods including X-ray diffraction (XRD), optical microscope, and Fourier Transform Infrared spectroscopy (FTIR) were used. The alteration in shale/water contact angles was evaluated based on Sessile drop method. The results show that SCCO2 treatment can alter the mineral composition of shales. Quartz content generally increased, while clay and carbonate minerals’ contents decreased. Evaluating the dissolution of carbonate minerals, in particular, is beneficial to form an effective mineral carbonation trapping for long-term CO2 storage. The changes in surface morphology suggest that clay-rich shales are more affected by SCCO2 treatment compared to sandy/quartz-rich shales. The aromatic hydrocarbons showed minor changes after SCCO2 treatment compared to the aliphatic hydrocarbons. The increase in oxygen-containing groups after SCCO2 treatment proves the high adsorption capacity of CO2 in shales. However, hydroxyl functional groups showed various trends after SCCO2 treatment, depending on the clay content. Eagle Ford shales displayed a possible turn to CO2-wet behavior, while the surface of Mancos shales remained strongly hydrophilic. In conclusion, quartz-rich shales could be favorable for CO2 adsorption and providing more storage capacity.

Magnitude and direction of in-situ stresses are crucial inputs of any geomechanical analysis when it comes to the stability of structures under different downhole conditions . There have been many approaches proposed to determine these parameters on the laboratory or field scales, but many presumptions, complications and difficulties are often involved. Deformation Rate Analysis (DRA) is one of these approaches proposed to determine the magnitude of in-situ stresses based on the Kaiser effect in the applications concerning near surface conditions. In this paper attempts are made to show the application of the DRA in determination of in-situ stress for unconventional shale gas reservoirs. A case study from the Perth basin in Australia was considered to examine the accuracy of the results on the field scale. It was found that compliant shale samples may not be able to provide a good estimation of in-situ stresses, but the DRA appears to be an effective method of in-situ stress determination for unconventional shale gas reservoirs. The elapsed time between the sample extraction and testing also plays an important role during the laboratory measurements while the impact of the loading cycle on the strength of the samples should not be ignored.

Rock typing is a process through which reservoir layers are classified into distinct units with similar geological conditions. The Kozeny-Carman's equation is commonly used for rock typing based on the porosity-permeability relationship, but it only considers spherical grains in its calculations which does not give representative results on many occasions. Thus, an attempt was made in this study to develop a new mathematical equation to correct the porosity-permeability relationship in rocks with ellipsoidal grains. To validate this equation, several pore-scale models were analysed using the Discrete Element Method (DEM) where the porosity was calculated under different conditions. The permeability of the pore scale models containing ellipsoidal (spheroidal) grains with different aspect ratios were then determined using the Lattice Boltzmann Method (LBM). This was followed by applying the new equation by incorporating the eccentricity of grains in the correction shape factor of the Kozeny- Carmen's equation. The results obtained indicated that any deviations in the sphericity of the grains (increase or decrease in the aspect ratio) increase the permeability of the model. In other words, the developed pore scale model with the aspect ratio of 1.0 (spherical grains) had the lowest permeability at the same porosity. This could be due to the bridging of pores with the ellipsoidal grains which causes a longer and narrower fluid path. Moreover, the models with the aspect ratio of 0.5 and 2.0 had a similar porosity-permeability correlation which could be linked to their similar packing structure. The new equation was further validated through the literature and numerical studies to ensure its accuracy under different geological conditions.

Surface wettability is a key factor controlling the CO2 seal capacity and defines the CO2 storage potential. Limited studies have addressed the shale/water wettability behavior during CO2 injection, thus considerable attention is needed to understand this concept. In this paper, an ample number of supercritical CO2 exposure experiments were conducted to evaluate the alteration of shale/water contact angles. Different types of shales with various mineralogy from Eagle Ford, Wolfcamp, and Mancos fields, were exposed to SCCO2 at different durations, pressures, and temperatures. Shale mineralogy and surface were analyzed using X-ray diffraction and scanning electron microscope. The results indicated a strong relationship between mineral composition and the alteration in shale/water wettability. Clay-rich shales displayed a possible turn in wetting behavior to CO2-wet with extending the SCCO2 treatment time and increasing the treatment pressure, caused by SCCO2 dissolution of clay and carbonate minerals. While the wettability of high-quartz contents shales remained strongly hydrophilic after various SCCO2 treatment conditions. Increasing the temperature accelerated the CO2/shale interactions, and a minor effect was observed on the shale hydrophilicity. Increasing the cohesive energy density of CO2 promotes a favorable CO2 wetting environment, which reduced the hydrophilicity of the surface and reduces the surface energy. In conclusion, shales with high quartz contents exhibit strong water wetting behavior after SCCO2 treatment, which leads to better sealing capacity, more efficient integrity of geological storage sites, and higher potential for CO2 containment.

Carbon capture and sequestration technology is a major approach developed to mitigate the amount of greenhouse gases released into the atmosphere. Technically, depleted oil and gas reservoirs are one of the feasible subsurface geologic media for large-scale carbon dioxide (CO2) storages. Trapping mechanisms during and after CO2 injection in geologic formations ensure the long-term safety and security of a storage task. However, depending on characteristics of geologic sites and subsurface conditions, different trapping mechanisms may come to play during sequestration, among which residual trapping is by far the most efficient one in a short-term scale. Although there have been many experimental and numerical studies carried out in the past years to evaluate this trapping potential prior to injection, there is not any field-scale approaches developed to assess CO2 residual trapping at the depletion stage of oil and gas reservoirs. The aim of this paper is to present a method for residual trapping assessment of CO2 storage sites by considering related and effective constraints such as residual hydrocarbon saturation, interfacial tension, pore geometry, and wettability. An analytical method based on a adjustment factor was proposed which could be used to determine the residual CO2 saturation/residual trapping for different rock types having different wetting characteristics. Two wells out of a total number of 20 wells (mostly depleted) from the largest gas field in Malaysia were considered as part of this study to show how the proposed method can be executed in the field scale for determination of the residual trapping ability of the reservoir. The results obtained indicated that the average residual CO2 saturation by the proposed method is around 26% and 27% for Well A and Well B, respectively. Thus, the maximum volume of CO2 residual trapped could be approximately 0.96 Tscf or 0.97 Tscf of the effective pore volume (excluding 30% Sgr), based on the average saturations estimated from the data of Well A and Well B. The results were validated both experimentally and numerically where it was found that the proposed method and three phase core flooding experimental data are in good agreement, indicating a strongly water wet system. However, more experimental studies on the core samples taken from the same field are required to further validate the results before fully implementing CO2 storage in the site.

Rheological and filtration properties of water based muds play vital roles to have a good drilling efficiency in high pressure high temperature (HPHT) environments. However, there are many occasions where controlling the variation of mud properties due to disintegration of additives is barely possible, resulting in stuck pipe, kick incident or even loss of wells. Although there have been many studies in the past indicating the application of nanosilica in improving the flirtation control of water base muds, there are almost no studies on the significant reduction of the yield point which may cause a huge decrease in cutting carrying capacity of muds and rate of penetrations. The aim of this study is to propose an approach to improve the filtration control of water based muds using nanosilica while maintaining the rheology by using a cationic surfactant. The results obtained from zeta potential measurements indicated that bentonite and nanosilica particles are both negatively charged at different ranges of pH, which would result in reduction of the yield point of the mud samples containing nanosilica. This issue was resolved by employing a cationic surfactant and following certain procedures. Filtration tests conducted under LPLT and HPHT conditions indicated that adding modified nanosilica into the mud samples creates a thin and low permeability filter cake without having any negative impacts on the rheology.

Undesirable water production due to water coning in hydrocarbon reservoirs has been a long-standing issue. This phenomenon decreases the oil production rate, increases the water cut and ultimately leads to early well-shutdown. Water coning may also interrupt the well testing data acquisition used to determine the reservoir permeability. In this study, attempts are made to propose a new approach which can control the water coning and estimate the reservoir permeability simultaneously. This was done by proposing a new boundary control model that was coupled by the Ensemble Kalman Filter (EnKF). A synthetic case study was considered to evaluate the performance of the EnKF associated boundary control (EnKF-ABC) approach. The results obtained indicated that the water cone development is controlled by the proposed method. In addition, the proposed method was also successful to estimate the reservoir permeability in the presence of water cone with less than 20% error after 12 times of downhole data acquisition. Even in the worst case scenario where there was a significant uncertainty in the initial estimated permeability, all the permeability ensemble members converged after about 200 days and tended to the real permeability after 500 days with less than 5% error. It was also observed that the Root Mean Squared Error (RMSE) of permeability sharply decreases when the ensemble size exceeds 15. The proposed approach is robust and reliable even where the mean of initial estimated permeability is considered quite far from the actual one. The EnKF-ABC approach proposed in this study can be applied to those production wells that suffer from water coning and there is lack of prior knowledge about the reservoir permeability.

There have been many studies on reservoir compaction where different mechanisms being suggested as the reasons behind the changes of porosity, permeability, and integrity of reservoirs during production. The theory of poroelasticity is often used to evaluate the likelihood of reservoir compaction, however, it has failed to explain the time dependent viscous behavior of unconsolidated formations. In this study, attempts are made to have a closer look into the compaction mechanism of deep-water sandstone reservoirs by bringing a case study from a gas field in Australia. The results obtained indicated that depending on the type of clays presented in the rock matrix, confining pressure and the loading rate, unconsolidated/poorly consolidated sandstone may exhibit an elasto-plastic or viscoplastic behavior during compaction. It was also found that the deformations initiated during compaction is a time-dependent process and can be a function of clay type in the sandstone matrix. It appears that kaolinite pushes the sandstone to exhibit an elastoplastic behavior while sandstones with a huge amount (more than 45%) of illite/smectite show a viscous (time dependent) response to hydrostatic loading. It was also revealed that the viscous behavior is induced once the confining pressure reaches a certain threshold (above 10 MPa). It seems that as the loading rate increases from 0.5 MPa/min to 1 MPa/min, a viscoplastic deformation dominates but an elasto-plastic response is revealed once the loading rate reduces to 0.25 MPa/min. It was concluded that the type of clays and their contribution in the rock matrix should be analysed very carefully to determine the geomechanical responses of deep-water reservoirs under different in-situ stress conditions.

With the advances of technology, many new well logs have been acquired over the past decade that carries vital information about the reservoir and subsurface layers. Thus, identifying the most relevant data that can improve the determination and prediction of petrophysical parameters has become very challenging. There has been an increase in the application of machine learning models that can accurately determine the petrophysical parameters of reservoirs, but further studies are still in demand. In this study, enhanced data analytics were used together with the visualisation techniques to pre-process the wireline logs acquired from the Volve field in the North Sea. Descriptive statistical methods were used to understand the relationship between the variables (input and output parameters), followed by applying the Extreme Gradient Boosting (XGBoost) regression model to predict the reservoir permeability and water saturation. A new ensemble model of Random Forest and Lasso Regularisation with an enhanced feature engineering technique was then proposed to improve the accuracy of the results. It appeared that the proposed ensemble model has a better performance than the traditional XGBoost and the hybrid PCA-XGBoost models in terms of precision, consistency and accuracy. The immense potential of ensemble modelling to enhance reservoir characterisation has been demonstrated by the success of this research.

There have been many studies carried out in the past decade to evaluate the long-term integrity of seals in CO2 storage sites. These seals (caprock and faults) are often dominated by shale and may act as a capillary barrier against the CO2 migration. Thus, geochemical reactions, mineral transformations, surface wettability alteration and reduction of capillary pressure that may take place in a geological storage site must be deeply understood. The main objective of this study is to examine the changes in the mineralogy and surface wettability of shales with different clay contents once exposed to supercritical CO2 for 6 months. The results obtained indicated that quartz dissolution and kaolinite precipitation can be induced in the presence of supercritical CO2. It appeared that brine in a concentration less than 4000 ppm could help to maintain the water wettability of the clay surface. Changes of surface wettability in a storage site could be a dynamic process and linked to the reduction of the surface areas in clays and their affinity to absorb CO2. Given that the interactions between CO2 and rocks are very slow and may take place over a long period of time, further studies are needed to ensure the integrity of seals in storage sites during and after injection.

The advent of Artificial Intelligence (AI) in the petroleum industry has seen an increase in its use in exploration, development, production, reservoir engineering and management planning to accelerate decision making, reduce cost and time. Supervised machine learning has gained much popularity in establishing a relationship between complex non-linear datasets. This type of machine learning algorithm has showcased its superiority over petroleum engineering regression techniques in terms of prediction errors for high dimensional data, computational power and memory. This review focuses on the most widely used machine learning algorithm employed in the petroleum industry, the Artificial Neural Network (ANN) with different shallow models used in reservoir characterisation. The Support Vector Machine (SVM) and Relevant Vector Machine (RVM) has over the years emerged as competitive algorithms where in most cases based on this review it outperformed the ANN. This makes it preferable than the ANN when there are limited data sets. Finally, hybridisation of multiple algorithms methodologies also showed improved performance over singularly applied algorithms offering a pathway in improving reservoir characterisation based on supervised machine learning as future scope of work.

Stability analysis of directional wells has been a long standing issue due to complexity of geological settings and changes in the stress coordinate system when wells are being deviated. Although there have been many studies developing strategies to estimate the safe mud weight based on wellbore geometry and anisotropy of subsurface structures, the issue of instability in deviated wellbores has been widely experienced in many fields around the world, especially in Malaysia and Australia. The aim of this paper is to present a workflow for estimation of geomechanical parameters and stress states of boreholes drilled directionally into anisotropic formations. A case study from one of the wells drilled into tight shales was brought into attention to evaluate the application of the proposed methodology. The results obtained based on the interpretations of data and reports of similar incidents in the field indicated that the well was deviated due to drilling parallel to the direction of bedding planes, causing creation of blocky, and tabular cuttings with parallel surfaces at shakers. The Horizontal Transverse Isotropic (HTI) model was assumed and the ANNIE model, developed exclusively for shales, was considered for estimation of stiffness parameters required to fully characterize shale formations. Determination of the safe mud weight window using two well-known failure criteria with proven applications revealed that a three-dimensional failure criterion should have been applied to prevent the instability of the wellbore wall. In fact, following the underestimation of shear failure provided by the Mohr-Coulomb criterion, a 13 ppg mud would have been selected to save the well, which in turn could result in enlargements of the well and significant increase of completion costs. Although some practical conclusions are provided, more studies are required to evaluate the application of the proposed methodology in other wells worldwide.

Failure of cement sheath due to casing expansion or formations pressure during completion or production stages of HPHT or deep vertical wells is a very common phenomenon. There have been many studies providing approaches to predict cement sheath failure, where theory of elasticity or thermo-elasticity together with the plane strain concept were taken into consideration to obtain representative results. However, sedimentary formations in subsurface layers are exhibiting a poroelastic behavior and theory of elasticity may not be able to fully describe their behaviors when changes in pore pressure and in-situ stresses are taking place. In this paper, an analytical approach based on the theory of thermo-poroelasticity was presented to predict the possibility of cement sheath failure in deep structures. A separate numerical molding was also performed to evaluate the application of the approach developed. The results obtained indicated that a thicker cement can withstand a higher load applied by the formations and protect the casing against a significant collapse pressure. The temperature was also found as a significant contributor in increasing the pressure applied by the formation and casing on the cement due to pore fluid and steel expansions. Although some discrepancies observed between the results of the numerical simulation and the analytical model, it seems that the approach presented is able to provide reliable results considering the fact that interactions of material interfaces could not be included in the analytical modeling.

A systematic and careful analysis of changes in the magnitude of geomechanical parameters is essential to mitigate the risk of leakage from CO 2 storage sites. However, depending on rocks and storage sites, these changes might be different due to chemical reactions taking place, especially when it comes to saline aquifers. There have only been few studies carried out in the past to evaluate the maximum sustained pressure of rocks being exposed to these chemical interactions. However, more studies are still required to evaluate the strength of the storage medium or seals when different kinds of rocks and fluids (fresh water or brine) are included in the hostile environment of a storage site. In this paper, attempts were made to evaluate changes in the variation of geomechanical parameters of the Berea sandstone during and after the injection of supercritical CO 2 in a short period of time. The results obtained indicated that the presence of brine in the pore space during injection enhances the severity of geochemical reactions, causing reductions in the magnitudes of elastic parameters including shear modulus. Having a good look into the SEM images of the sample before and after exposure to scCO 2 indicated that these changes can be attributed to the dissolution/fracturing of calcite and clays in the matrix of the sample. Although findings were provided based on the pulse measurements tests, more studies are required to have a deeper understanding as to how geochemical reactions may cause difficulties during and after injection into a storage site.

Carbon dioxide (CO2) storage in subsurface geologic medium is presently the most promising option for mitigating the anthropogenic CO2 emissions. To have an effective storage in immobile phase, however, it is necessary to determine the distribution of CO2 in a medium, which mainly depends on three trapping mechanisms known as capillary, dissolution and mineral mechanisms. Previous studies have emphasized on these mechanisms individually in different aspects, particularly by considering the aquifer system. The purpose of this review is to give a comprehensive discussion on the advancement made toward capillary trapping in terms of effective and non-effective factors. It also throws light into the importance of capillary trapping in depleted hydrocarbon reservoir. Considering various factors and their impacts on capillary trapping, it is suggested to carry out an integrated study for the assessment of the major and minor influential parameters for better modeling and understanding of capillary trapping in any storage medium.

Shale reservoirs have gained the attention of many in recent years due to their potential as a major gas resource. Production from this kind of formation, however, requires an accurate estimation of brittleness and employments of hydraulic fracturing. There have been many studies as to how brittleness can be estimated, but few research works were carried out so far indicating how brittleness indices vary in gas shale formations. The aim of this paper is to evaluate the variation of brittleness in one of the gas shale reservoirs located in the north Perth Basin of Australia. The results obtained indicated that the lower part of the Carynginia shale should be selected for a hydraulic fracturing job due to a high brittleness index, although a careful analysis of Total Organic Content (TOC) might be required before initiating any plans. The mineralogical report and interpretations revealed that the space created by cross-plotting the elastic parameters is able to identify dominant minerals contributing into brittleness. Performing a series of true triaxial tests, which are capable of simulating the real field condition by applying three independent principal stresses, implied that as the stress anisotropy increases, a transition takes place from brittle towards the ductile behaviours. However, when this anisotropy becomes significant, samples regain their strength. This study, therefore, recommends more studies to get a practical conclusion on brittleness under true triaxial conditions.

Carbon Capture and Sequestration (CCS) technology is an effective strategy to mitigate greenhouse gases released into the atmosphere. One of the challenges of the CCS sites, however, is the degradation of class G cement used to seal-off the injected intervals. It is known that in the presence of brine in depleted reservoirs or aquifers, cement may degrade due to the interaction of its alkaline component (Portlandite) with carbonic acid, causing seepage of CO2 and environmental contamination. Given the surface area, stability and inhibition characteristics of nanomaterials, they might be a good option to improve the performance of the cement in CO2 storage sites. In this study, attempts are made to show how two reliable nanomaterials (Nano Glass Flakes (NGFs) and Multiwall Carbon Nano Tube (MWCNTs)) can be used to improve the integrity of the cement in CO2 storage sites. A series of pre-carbonation and post-carbonation tests were conducted on the cement samples modified by NGFs and MWCNTs to compare their performances under a real storage site condition. It was found that the samples with 0.5 wt% NGFs and 0.05 wt% MWCNTs have the best performance against the attack of CO2. They could significantly resist against the carbonation and prevent the severe chemical reactions taking place in the presence of CO2. Given the fact that NGF is significantly cheaper than MWCNT, it could be a good choice to reinforce the cement used in the CCS storage site.

Exact prediction and controlling of surge/swab pressure are required during drilling of hydrocarbon reservoirs and other geological formations that often leads to well control challenges. The existing methods to predict the surge/swab pressure gradient in the wellbore are much implicitly developed, which further reduces the model accuracy. Therefore, the present research aims to develop a novel analytical model by incorporating the explicit flow velocity equations to further improve the efficiency in predicting the surge pressure gradient. The governing flow velocity equations are developed for a concentric annulus exhibiting Couette–Poiseuille flow phenomenon that subsequently used in designing a new analytical model for yield power-law fluids to predict surge pressure gradient. Detailed analysis for the validation of a newly developed model is performed using existing predictive models and experimental data of surge pressure. The statistical analysis exhibits satisfactory outcomes with a maximum error of 5.61% and R2 of 0.988. A detailed analysis on the effect of relevant parameters on surge/swab pressure is also presented. The impact of fluid behaviour index and diameter ratio is found to be highly dependent on surge pressure under varying tripping speeds compared to other drilling parameters such as fluid yield point and consistency index.

Interfacial Tension (IFT) is one of the most important parameters controlling the production during enhanced oil recovery phase. However, carbonated water injection (CWI), despite its reported applications, has not been totally successful to reduce the IFT between oil and brine. On the other hand, low salinity water (LSW) has been indicated as an effective method of reducing the IFT. Thus, if the CWI can be combined with LSW, with the mechanisms understood, a great step can be taken towards a better production from depleted reservoirs. In this study, the application of low salinity carbonated water (LSCW) injection was studied and attempts were made to understand the mechanisms involved in the presence of salt ions (NaCl and CaCl2) and carbon dioxide. The results obtained indicated that increasing the solubility of CO2 within the aqueous phase reduces the equilibrium interfacial tension (EIFT). It was also found that the EIFT of LSCW decreases by 51.8% compared to high salinity water during the laboratory measurements. It appears that the aging time was can improve the surface performance of the carbonated water (CW) once LSW is used. Furthermore, IFT reduction over time in LSCW was higher than the high salinity carbonated water (HSCW). It was argued that “salting in” effect is the major mechanism behind the reduction of IFT during the LSCW injection. Therefore, LSCW flooding can be considered as a competent enhanced oil recovery (EOR) method which can reduce the IFT and increase the microscopic efficiency for a better production.

Geomechanical analysis and integrity assessment of hydrocarbon reservoirs upon depletion and injection are crucial to ensure that CO2 storage projects can be safely implemented. The Bredasdorp basin in South Africa has a great potential for CO2 storage given its hugely available exploration data. However, there has not been any geomechanical characterization carried out on this basin to determine its integrity issues. The aim of this study is to provide a guideline as to how geomechanical analysis of depleted fields can be done for a safe CO2 sequestration practice. The results obtained from the geomechanical model constructed for the depth of 2570 m indicated that the magnitude of the principal vertical, minimum and maximum horizontal stresses in the field are respectively 57 MPa, 41 MPa and 42–46 MPa, indicating the presence of a normal faulting regime in the caprock and the reservoir. However, according to the pore pressure-stress coupling assessment, this normal faulting is much severe in compartment C3 of the reservoir. Fault reactivation and fracture stability were also investigated after depletion and it was found that faults in the compartments C1 and C2 are stable after depletion. However, normal faults (FNS8 and FNS9) in compartment C3 dipping SW were critically stressed and may be reactivated without a proper injection planning. Fractures in compartment C3 were also critically stressed, highlighting a great potential of leakage from this compartment upon injection. It was also revealed that the sustainable maximum fluid pressure of 25 MPa would not induce any fractures in the reservoir during CO2 storage.

Smart water flooding (SWF) has been successfully implanted in many fields around the world for the past decades. In this approach, smart water is injected into the reservoir to change the surface characteristics of rocks and improve the oil recovery. However, the presence of sulfate ions in the smart water and their interactions with the cations dissolved in the formation water (FW) may generate what is called scale. There have been several approaches proposed so far to inhibit the scale formations under different conditions but limited success has been reported to the application of these methods once tested under the reservoir conditions. In this paper, a nanomaterial based approach is proposed to inhibit the scale formation during SWF. Nano Glass Flakes (NGFs) and nano silica were considered as two effective nanomaterials in this study and a series of measurements were made to ensure that the scale formation can be inhibited under different temperature and salinity conditions. The results obtained indicates that if the nanoparticles can be properly dispersed in the smart water solution, the likelihood of the scale formation can be significantly decreased and the conductivity can be increased to 0.69 and 0.65 mS/cm for NGFs and nano silica solutions at 50 °C. It appears that NGFs provide a far better performance as temperature rises while nano silica loses its performance. It is also found that the nanoparticles perform better in a high saline water and can be an effective choice for SWF in the concentration of 0.05 wt%. It is also noted that the conductivity improvement made by NGFs in a high salinity water is 0.9 mS/cm while that for water with a low salinity conductivity is 0.23 mS/cm. Given the fact that the nanoparticles used has huge negative surface charge, reduction of the scale formation might be linked to the cations adsorption in the solution but may need further studies.

The Niger Delta, as an actively producing oil and gas region has potential to develop into a new CO2 geological storage hub. Criteria for screening basins for Carbon Capture and Storage (CCS) was used in combination with 3D seismic data and well information to assess the basin's potential in this contribution. It is shown here that the presence of excellent reservoir-seal pair, very large basin size, suitable reservoir depth, matured oil and gas fields, moderate faulting intensity, availability of giant hydrocarbon fields and being a passive margin generally makes the Niger Delta basin excellent environment for CCS. High resolution 3D seismic dataset and well information from case study areas enabled identification of potential reservoir, traps and seals. Geomechanical analyses have shown that slip tendency is generally low while fracture stability is high, which indicates that the study area is stable in the current stress regime.

Carbon dioxide released into the atmosphere due to anthropogenic activities has raised the alarm of global warming in the near future. CO2 storage in suitable subsurface geologic media has, therefore, been triggered in recent years. However, identification of suitable sites to store a large quantity of CO2 for a long period of time is not an easy and straightforward task. Although, a general criterion has already been presented based on local-scale projects in which depth, permeability, porosity, density and containment factors were considered for selection of an appropriate geologic medium, there are many other preliminary factors linked to the storage capacity, injectivity, trapping mechanisms, and containment which should not be neglected during a CO2 storage site selection. The aim of this paper is to propose a new screening criterion for the CO2 storage site selection based on a group of key parameters including reservoir and well types, classes of minerals, residual gas and water saturations, subsurface conditions, rock types, wettability, properties of CO2, and sealing potentials. These parameters were combined with those factors presented earlier by other scholars to provide a good insight into the suitable selection of storage sites. Although attempts were made to consider the whole parameters linked to a site selection, more studies are still required to get a final conclusion about the effective parameters which should be a part of the analysis.

Global warming arising from the release of greenhouse gasses into the atmosphere is one of the biggest issues attracting a lot of attention. One of the conventional problems in sequestration projects is the degradation of Portland cement due to its exposure to supercritical CO2. This paper gives a review on the laboratory work performed to understand changes in the mechanical and transport properties of cement when it is in a CO2 rich environment. The results obtained indicated that pozzolanic material could be useful in enhancing the cement resistance against CO2, although more studies are still required to confirm this conclusion.

CO 2 injection for storage in subsurface geologic medium is one of the techniques developed in the past years to mitigate anthropological CO 2 . Prior to CO 2 injection, it is essential to predict the feasibility of medium in terms of storage capacity, injectivity, trapping mechanisms, and containment. There have been many studies regarding techniques which can be applied to ensure the safety of CO 2 injection. However, there are few studies indicating the importance of capillary trapping during and after CO 2 injection. The aim of this study is to review the fundamentals of injectivity and its relationship with capillary trapping for CO 2 storage in depleted oil and gas reservoirs. Considering the number of effective parameters which are associated with the injectivity and capillary trapping, it is recommended to perform a comprehensive analysis to determine the optimum injection rate and safe storage medium before operation.

The determination of the most unstable areas in oil fields is critical for addressing engineering problems of wellbore and sand production as well as geologic problems such as understanding dynamic constraints on hydrocarbon migration and fracture permeability. In this research work, coherency seismic attribute has been used for the determination of the most critical areas in terms of drilling stabilities in the DQ oil field, Iran. The results obtained have shown that the (1) predominant features are the SSE–NNW and N–S trends (2) the central part of the DQ structure shows the highest concentration of segment bundles, (3) the segment bundles seem to be aligned along some lineaments oriented SE–NW and SSE–NNW, and (4) on the eastern and western margins of the map there is an anomalous concentration of segments oriented E–W. It can be concluded that coherency attribute is a valuable tool for structural analysis highlighting those areas containing unstable features.

Carbon Capture and Sequestration (CCS) technique is an effective strategy developed in the past decade to reduce the amount of CO2 emission in the atmosphere. Integrity of storage sites plays an important role in the success of a CCS project once CO2 is injected in a suitable geological formation such as depleted hydrocarbon reservoirs. However, the interactions of supercritical CO2 with the cement in the presence of brine may degrade the cement in the injection intervals, causing seepage of CO2 to surface or subsurface resources. In this study, efforts are made to show the application of agricultural wastes and nanomaterials as potential pozzolanic additives which can improve the performance of the cement once exposed to CO2. Palm Oil Fuel Ash (POFA) and Rice Husk Ash (RHA) as agricultural wastes together with Nano Silica (NS) were used in this study. Two series of tests, known as pre-carbonation and post-carbonation, were conducted and comparison was made between the agricultural and nanosilica cement composites. The results obtained indicated that the cement with 5 wt% POFA and 0.5 wt% NS can provide the highest compressive strength after 24 h of curing. The viscosity of the cement composites with NS and RHA also increased with the increase of the replacement level. A series of carbonation tests was done for 40 days and it was found that almost all of the cement samples provide a better performance than the neat cement in the CCS sites, although the best result was obtained by the samples with 0.5 wt% NS and 0.75 wt% NS given the interactions that may take place faster in the nanoscale.

Conventionally, high frequency Dipole Shear sonic Imager (DSI) logs are used for anisotropic modeling where fast and slow shear wave's velocities are required. However, the results obtained from a DSI log are restricted to a specific and possibly short interval of the wellbore. The aims of this paper are to use Vertical Seismic Profile (VSP) data and show its application in geomechanical analysis of subsurface layers under anisotropic condition. After processing and separating upgoing and downgoing P- and S-waves, a methodology based Vertical Transverse Isotropic (VTI) condition was presented to determine elastic stiffness parameters. Having stiffness parameters determined, elastic modulus, strength and in-situ stress parameters were estimated and calibrated against the field and core sample data. Although the VSP based geomechanical parameters were calibrated against the real field data, the accuracy of the method cannot be as much as that of the well logs. However, the method presented in this paper may become a very good asset for geomechanical evaluation of the intervals where well log data are not available.