Most of the studies regarding the formation and stability of emulsions focus on the conditioning and management of crude oil on surface facilities. Since a great deal of the crude oil produced is in the form of stable emulsions, it is often claimed that these emulsions are formed through chokes and other flow constrictions in oil field equipment. However, emulsions are produced in wells, which not only lack these constrictions but also are produced at low flow rates, demonstrating the fact that emulsions can be formed within the well itself. The present work reviews the literature regarding the formation and properties of heavy and extra-heavy oil emulsions in naturally fractured porous media due to the current relevance that these types of crude oil exploitation take, satisfying the hydrocarbon energy demand. Moreover, emulsions have received more attention recently since they can be formed in-situ and improve oil recovery. To understand the flow mechanics of emulsions in porous media, different models to describe their transportation are presented. Finally, the formation of emulsions in the reservoir for enhanced oil recovery purposes, including the use of nanoparticle-stabilized emulsions is discussed.

With increasing global demand for energy, the importance of unconventional shale oil and gas research cannot be over-emphasized. The oil and gas industry requires rapid and reliable means of forecasting production. Existing traditional decline curve analysis (DCA) methods have been limited in their ability to satisfactorily forecast production from unconventional liquid-rich shale (LRS) reservoirs. This is due to several causes ranging from the complicated production mechanisms to the ultra-low permeability in shales. The use of hybrid (combination) DCA models can improve results. However, complexities associated with these techniques can still make their application quite tedious without proper diagnostic plots, correct use of model parameters and some knowledge of the production mechanisms involved. This work, therefore, presents a new statistical data-driven approach of forecasting production from LRS reservoirs called the Principal Components Methodology (PCM). PCM is a technique that bypasses a lot of the difficulties associated with existing methods of forecasting and forecasts production with reasonable certainty. PCM is a data-driven method of forecasting based on the statistical technique of principal components analysis (PCA).

In our study, we simulated production of fluids with different compositions for 30 years with the aid of a commercial compositional simulator. We then applied the Principal Components Methodology (PCM) to the production data from several representative wells by using Singular Value Decomposition (SVD) to calculate the principal components. These principal components were then used to forecast oil production from wells with production histories ranging from 0.5 to 3 years, and the results were compared to simulated data. Application of the PCM to field data is also included in this work.

This study provides fresh initiatives into how production forecasting from unconventional LRS reservoirs can be done in a different way.

This paper introduces new approach for pressure-rate convolution and deconvolution analysis of multi-stages hydraulically fractured conventional and unconventional reservoirs. This approach demonstrates the impact of variable Sand face flow rate on reservoir performance. A new model for P/R deconvolution is used to convert pressure pulse from variable flow rate to single and constant rate response. The target of this study is fractal reservoirs with and without stimulated and unstimulated reservoir volume.

Multi-linear flow regimes approach is used to describe pressure behavior in the reservoirs while decline flow rate behavior is described by newly proposed model in this study. This model depicts, instead of van Everdingen model, indirectly the declining rate with time by using pressure responses with production time. Decline flow rate behavior simulated by linear and bi-linear flow models are also studied and compared with the one obtained by the new model. Several analytical models are used in this study by applying P/R convolution and deconvolution technique and solved for constant and variable flow rate considering different reservoir configurations and operating conditions. The results are interpreted and analyzed for better understanding pressure behaviors, flow regime types, and productivity index trends for continuously changing flow rate especially at early production time. Estimating stimulated reservoir volume (Vsrv) is considered one of the applications of convolved pressure since it is calculated from pseudo-steady state flow when late time boundary dominated flow regime is reached.

The outcomes of this study can be summarized as: 1) Introducing new approach for pressure-rate convolution and deconvolution technique for multi-stages hydraulically fractured reservoirs by applying new decline flow rate model that indirectly simulates variable flow rate with time. 2) Generating analytical models for dimensionless pressure and flow rate for constant and variable flow rate using the concept of P/R convolution and deconvolution. 3) Comparing the result of newly proposed models with the results obtained by applying van Everdingen model for decline rate behavior. 4) Studying the applicability of linear and bi-linear flow models in converting variable flow rate pressure response to single and constant flow rate pressure response. 5) Applying the deconvolution technique to simulate pressure response at late production time to estimate stimulated reservoir volume.

The most interesting points are: 1) The main difference in wellbore pressure behavior between variable and constant flow rate can be seen at early production time, however intermediate production time could also show very limited changes for the case of variable rate wellbore pressure. 2) A unit slope line flow regime could be developed for varied flow rate pressure response at very early production time similar to the wellbore storage dominated flow regime. 3) Productivity index calculated by the proposed models for variable flow rate is greater than the index for constant flow rate. 4) The impact of petrophysical properties of porous media and hydraulic fracture characteristics on pressure response are similar in the two cases of variable and constant flow rate. 5) The decline rate models for linear and bi-linear flow are not applicable in pressure deconvolution technique.

The transport properties of fluids in nanopores are a Fundamental scientific issue in the development of tight reservoirs such as shale gas. The flow of gas in nanosized pores is affected by a size effect, therefore, the conventional fluid mechanics theory cannot be applied. Based on the molecular dynamics theory, the transport process of methane in carbon nanopores was studied, including simulation of the arrangement of the wall atoms, slip and transitional flow of methane in the supercritical state and application of different driving forces. The research of this paper revealed that the configuration of the wall carbon atoms, at the microscale, has a greater influence on the density distribution and velocity distribution of methane molecules in the pores, while the change in the driving force has a greater impact on the slippage of methane at the boundary. Particularly, the theoretical model we proposed can predict the transport properties in carbon nanopores, demonstrating the sensitivity of driving force, pore configuration and the state of flow for methane gas transport, which can provide the characteristic parameters for the establishment of the seepage mathematical model.

Among the several activities involved in oil exploration are the determination of hydrocarbon in-place and mechanical competency of the oil reservoir. The pressure regimes of the formation have also become vital properties which must be well known to ensure preliminary awareness of the hydraulic fracturing. This study seeks to adopt a prediction strategy of the overall geo-mechanical competency and strength of the formation, using a less stressful computational process and an empirical analysis, developed using three wells from ED BON area in parts of Niger Delta.

Elastic constants such as Poisson Ratio, Young's, Shear and Bulk moduli which are the parameters for characterizing rock mechanical properties were estimated, as well as the subsurface formation pressures and the associated fracture gradient using P-wave sonic and density logs.

The results from the analysis showed that there is correlation between elastic strength and fracture pressure.

This paper deals with the comparison of models for predicting porosity and permeability of oil reservoirs by coupling a machine learning concept and petrophysical logs. Different machine learning methods including conventional artificial neural network, genetic algorithm, fuzzy decision tree, the imperialist competitive algorithm (ICA), particle swarm optimization (PSO), and a hybrid of those ones are employed to have a comprehensive comparison. The machine learning approach was constructed and tested via data samples recorded from northern Persian Gulf oil reservoirs. The results gained from the machine learning models used in this paper are compared to the relevant real petrophysical data and the outputs achieved by other methods employed in our previous studies. The average relative absolute deviation between the approach estimations and the relevant actual data is found to be less than 1% for the hybridized approaches. The results reported in this paper indicate that implication of hybridized machine learning methods in porosity and permeability estimations can lead to the construction of more reliable static reservoir models in simulation plans.

Oil and gas operators worldwide are expecting service companies to deliver integrated techniques to minimize, if not prevent, drilling problems. Drilling fluids perform vital functions to ensure the success of drilling operations. The technical challenges often associated with water-based drilling fluids are loss of critical properties, such as fluid loss control and rheology, under demanding conditions, such as in drilling deeper, high-temperature and high-pressure wells. Fluid loss during drilling operations has a very significant effect in both reservoir formation damage and monetary terms. The use of durian rind (DR) as a new additive in controlling lost circulation would provide another opportunity to reduce waste and avoid pollution. Therefore, DR was used to improve the rheological properties of water-based mud, and it was prepared for use as a fluid loss additive. For a better understanding of the influence of pectin on drilling mud properties, the rheological evaluation of untreated DR was compared to that of mud samples containing treated DR. The pectin in DR was extracted using four different solvents, namely, ethanol, methanol, sodium hydroxide and hydrogen peroxide, and the most effective solvent to remove the pectin was then determined. The Fourier transform infrared spectroscopy (FTIR) results showed that NaOH was the best solvent for removing pectin from DR. Thermogravimetric analysis (TGA) was used to determine the thermal stability of DR before and after treatments. The TGA results demonstrated that the treated DR had improved thermal stability compared to untreated DR. The sizes of DR used were coarse, medium, and fine. The untreated DR presented better rheological properties than the treated DR. The experimental investigation showed that a concentration of 20 lb/bbl of intermediate-sized DR was the best concentration among the tested samples.

Fluid flow in hydrocarbon reservoirs and consequently optimum scenario for hydrocarbon production, is heavily influenced by reservoir heterogeneities. Faults are one of the most common types of heterogeneity found in reservoirs. Leaky faults, baffles (limited extent faults) and complex multiple fault geometries are among the most complicated and important types of faults that are difficult to characterize. Leaky faults, unlike the sealing faults, are in partial communication with other portions of the reservoir. Because of faults' effect on reservoir connectivity and possible infill drilling plan for accessing all parts of the reservoirs, possible communication across the fault must be precisely modeled.

In order to detect the effect of a fault on communication within the reservoir, we need to analyze dynamic data. There are a few analytical methods for modelling partially communicating faults, however, these methods may not be accurate enough and may be limited in application, especially in complex situations. Numerical methods (i.e. finite difference or finite element) are also not computationally economical when a large number of grid blocks are simulated. In the current work, the Fast Marching Method (FMM) is applied to effectively mimic fluid flow in the heterogeneous areas, such as complex faults. It is shown that FMM can capture the effect of different fault configurations on the bottom hole pressure and is also able to capture different linear, radial and spherical flows.

Scale formation due to the mixing of injection water with formation water causes formation damage and reduction in petroleum production. By using scale inhibitors, scale formation/scaling could be prevented. In this work, static experiments were performed with rapid controlled precipitation tests, which were undertaken using three different scale inhibitors namely Falat scale inhibitor, Scahib 760 scale inhibitor and Scahib 780 scale inhibitor. Results show that parameters such as temperature and pH have significant effects on scale inhibitor efficiency. In this study, at pH of 7.8-9 it was found that an increase in pH can lead to a decrease in SI efficiency. In addition, acquired data shows that Falat scale inhibitor is more efficient at 45 °C but scale inhibitors (Scahib 760, 780) have better efficiencies at 25 °C. SEM tests were performed to find structure deformation and morphology of precipitation crystals, which indicated that scale inhibitor can have various effects on crystal's shapes. Finally, dynamic tests were performed with coreflood equipment that indicated higher recovery by using the scale inhibitors. The dynamic tests results show that the recovery factor in the presence of Scahib 760 scale inhibitor is about 58% and breakthrough time is 2099 (sec). In the absence of scale inhibitor, the recovery factor is about 52% and breakthrough time is 2720 (sec).

Pre-existing natural fractures and other structurally weak planes are usually well-developed in unconventional reservoirs. When such fractures intersect with hydraulic induced fractures, they will redirect and propagate as an important mechanical principle of volume fracturing by the formation of complex fracture networks. Under the shadow effect of natural fractures and other structurally weak planes with hydraulic Supported fracture stress, hydraulic fractures do not fully propagate in the direction of the maximum horizontal-principal-stress. This paper computed the stress intensity factors of hydraulic fracture types I and II by integrating the various interactions, established universally-applicable mechanical principles for the propagation behavior when a hydraulic fracture propagating in an arbitrary direction intersects with a natural fracture at an arbitrary angle, and demonstrated the mechanical principles of the intersection between hydraulic induced fractures and pre-existing natural fractures. This study proved the following conclusions: as the intersection angle between the hydraulic fracture and the maximum horizontal-principal-stress increased, the possibility of the hydraulic fracture being captured by the natural fracture with an identical approaching angle first increased and then decreased; as the net stress increased, the intersection behavior between the hydraulic fracture and the natural fracture transitioned from penetration to capture.

The hydraulic fracturing operation is highly complex in fractured reservoirs. The Fundamental key to a successful operation is processing and analysis of the propagation of hydraulic fracturing in a natural fracture network. In this paper, the hydraulic fracturing process is evaluated in a fractured reservoir in southwest Iran. The developing process of induced fracture in a natural fracture network is analysed by the Distinct Element Method (DEM). After determining the fluid flow regime in the natural fractures of the reservoir, hydraulic fracturing is applied along different lengths of the reservoir and in each range, the production rate is checked. Fluid flow in natural fractures after the hydraulic fracturing operation is shown and evaluated in order to evaluate the induced fracture effectiveness in enhancing fluid flow regimes in the reservoir. The reverse suction phenomenon which causes changes in the fluid flow pattern in fractures and will thus affect the production rate is also studied in this paper. Fracture coalescence will cause the induction of natural fractures to hydraulically fracture without their intersection; this is one of the significant parameters in hydraulic fracturing in naturally fractured reservoirs which is also discussed in detail. This paper can present valuable information on fluid flow analysis before and after applying hydraulic fracturing in a fractured reservoir and solve some essential ambiguities in this area.

Nowadays many of oil and gas wells are drilled extensively by Polycrystalline Diamond Compact (PDC) drill bits. Various companies are manufacturing PDC cutters according to their usage. All of these companies concentrate their products of PDC cutters to be well resisting for abrasive wear. The wear of PDC inserts leads to money loss as well as delays the drilling procedures causing unexpected dilemmas. Therefore, it is crucially significant to evaluate the quality of the PDC cutters based on their resistance against abrasive wear.

The present work concentrates on assessing the PDC cutters from various sources using two non-destructive analytical approaches: Raman-Shift and Fourier Transformation Infrared Ray (FT-IR) spectra. The analysis of the PDC samples with the analytical techniques were validated with the previous experimental results obtained from micro and nano-scratch tests achieved on the same specimens.

The presented work could be performed on many PDC cutters from various manufacturers as the applied tests considered non-destructive compared to the traditional destructive techniques which leads the way for evaluating lots of PDC cutters without causing any damage. The analysis of the applied analytical approaches agreed with the results obtained from previous experimental scratch tests.