Porosity is one of the most important characteristics for modeling reservoir. In recent years, some new methods for estimation have been introduced, which are more applicable and accurate than old methods. Fuzzy logic has shown reliable results in petroleum modeling area for describing reservoir characteristics. In this study, a Sugeno fuzzy model has been formulated to predict porosity. In order to select the number of membership function, subtractive clustering method was utilized through Gaussian membership functions. Another technique for predicting porosity was multiple linear regression to compare with fuzzy logic technique. Results indicated that correlation between real value from core data and the predicted value by fuzzy logic was more accurate than multiple linear regression technique in this scope.

The gas injection mechanism is the common way to enhanced oil recovery of carbonate reservoirs. This mechanism brings some difficulties such as viscose fingering, gas override issues and etc. In order to tackle these problems, foam assisted mechanism is used. Although, there are various studies about foam flooding and foam transport modeling in literatures, the lack of a brief and informative study about foam process modeling, in which all the previous models are included, is obvious. Thus, a brief review of foam modeling through porous media is the aim of this work. In this study, foam definition and foam properties were described in details, properties such as critical micelle concentration, foam quality, viscosity, stability, surface tension, foam disjoining pressure, etc. Also, major foam dynamic processes; foam destruction, formation, and entrapment, were explained in this work. Furthermore, three different approaches for modeling foam-assisted process through porous media were reviewed; the empirical, semi-empirical, and mechanistic, and the advantages and disadvantages of each approach were discussed.

In this paper a gas condensate reservoir with 33Gscm initial gas in place with total production of 15.8Gscm from 7 producers within 19 years production history is studied. The result of simulation study shows the reservoir can be appropriate candidate for underground gas storage execution. The result of the study also shows gas injection in the reservoir, significantly prevents condensate loss. It is also possible to inject 20MscmD in 8 months and produce 40MscmD in 4 cold months. The model is well fitted with 95 percent level of confidence.

Artificial neural networks have been becoming increasingly popular in oil industry over the last decades. But there was not a specific framework and procedure to design appropriate networks in respect to the problem. One of drawbacks of neural network application is its dependence on designer’s experience. In this work we proposed a method in which we design an artificial neural network coupling it with a genetic algorithm to not only optimize weights and biases but also number of neurons and connections. This method can be used to design complex systems in which time and simplicity are important factors as we used it in predicting gas lift aided recovery to obviate the need to run simulation software which is expensive and time consuming. First we create a network with neural network toolbox of MATLAB. This network was built fully-connected. Then we start our program with this initial guess and compare the final structure and mean square error (MSE) with the network created by MATLAB. The network obtained by our program was simpler and also it has lower MSE indicating a network that is simpler and more accurate.

Baram Delta is the most prolific hydrocarbon province of all the geological provinces in the Sarawak Basin. Major fossilferous intervals have been identified within these units. The objective of this paper is to investigate the impact of diagenetic processes on fossils in fossilferous sandstones and how such modifications to fossils influence porosity and permeability. Seven wells from four fields in the Baram delta were evaluated using thin sections, CT scan imaging, SEM, EDX, spot permeability, core plug porosity and permeability measurements. Intragranular pores have been formed within fossils by dissolution of fossils. The formation of these pores has been facilitated by uplift of the Rajang Group accretionary prism to form the Rajang Fold-Thrust Belt. An increase in porosity and permeability is observed in both spot permeability and core plug porosity and permeability measurements in the fossilferous sandstones. Spot permeability in fossilferous part of the sandstones range between 606mD-879mD whereas the non fossilferous part has spot permeability values ranging between 305-521mD. This represents a permeability enhancement of 50-60% in the fossilferous part. Core plugs from the fossilferous horizons have porosity between 18-30% and permeability ranging between 662mD-683mD whereas the non fossilferous horizons have porosity between 13-27% and permeability ranging between 10-529mD.

Based on principle stress theorem, the effective stress changes in the reservoir and its surrounding formation tightly coupled with pore pressure changes due to reservoir fluid withdraw or injection. Rock mechanical deformation induced by evolution of effective stress would be controlled through paths in which the reservoir stress follows during pore pressure alterations. The stress path that the reservoir conforms all over history of production undoubtedly affects the mechanical behaviour of the reservoir and fluid flow characteristics and could be one of the key factors in measurements and calculations of geomechanical instabilities related to pressure depletion/injection. The stress path additionally, has a considerable influence on recovery drive mechanism, straightly through compaction drive, and indirectly through permeability variation. Furthermore, the stress modifications in the reservoir and bounding formation possibly lead to changes in seismic attributes and consequently disturbing time-lapse (4D) seismic response. Other associated geomechanical problems include wellbore instability, casing collapse and solid production are strongly related to the stress path that reservoir and its burdens follow during production. Reservoir stress path and its changes throughout reservoir depletion are strongly dependent on several geological and mechanical factors such as reservoir boundary, reservoir dimension and its shape, constitutive behavior of reservoir rock and surrounding formations, and so on. A coupled hydromechanical model that includes above mentioned parameters was extended to more precisely forecast the reservoir stress state changes and to investigate the influences of these factors on reservoir behaviour. The main goals of this Paper are to explore which factors have the significant impact on the stress path, and to consider the effects of stress path on hydromechanical behaviour of a depleting reservoir. Numerical modelling results confirm that reservoir stress path is associated with the dimension and geometry of the reservoir and on poroelastic properties of the reservoir rock and bounding formations. Also we have shown that permeability reduction of the reservoir through fluid withdraw strongly depend on magnitude of the reservoir stress path.

Under balance drilling often in order to reduce formation damage, lost circulation reduction and increase the rate of penetration is investigated. Wellbore instability due to high expenses and personnel likely to endanger the drilling, a major concern in the oil and gas industry will be created. Wellbore instability with under balance drilling has a direct relationship, so that the main requirement for Evaluation of under balance drilling wellbore stability, is wellbore stability.in this paper, the wellbore stability in one of oil fields of Iran by Adaptive Neural Fuzzy Inference System for Evaluation of under balance drilling has been evaluated. The results showed that to achieve this goal, using this system is well suited and could predict valuable and accurate results. Finally, it was concluded that there is a mean square error between experimental data and predicted model which are 0.002136 and 0.00006038 for training data and test data, respectively.

Sand production is an important challenge in upstream oil and gas industry, causing operational and safety problems. Therefore before drilling the wells, it is essential to predict and evaluate sanding onset of the wells with the intention of drilling trajectory optimization. In spite of choosing optimized trajectory, in some producing wells by variation of well production condition, sand production may be occurred. So in this situation, appropriate well completion design is crucial. This research considers sanding problems in two steps. At the first stage, an analytical sand prediction model using Mogi-Coulomb failure criterion was presented for determination of maximum sand free drawdown. In this model, by changing the drawdown and wellbore trajectory, sand failure will be predicted by comparing the sand strength to the failure criteria. The results show that in different in situ stress regimes the inclination and azimuth have a significant role in wellbore stability during production. At the second stage, by considering a well with sanding problem, different well completion scenarios were simulated and modelled in order to select the optimum well completion method.

Prediction of viscosity of natural gas is an important parameter in the oil and gas industry as it has a major effect on gas engineering calculations including reservoir recovery, fluid flow, deliverability, and storage. Gas viscosity is determined directly by experiment, but if unavailable, predicted by empirical correlations. An accurate prediction of natural gas viscosity is needed in the appropriate design and operation of equipment in industrials and processing. In this work, by means of an artificial neural network which is a branch of Artificial Intelligence and a powerful tool for prediction, gas viscosity of hydrocarbon mixtures is predicted in a wide range of pressure and temperature. Therefore, different networks with variable layers and neurons in each layer are trained and tested by different training algorithms. Then, the network with minimum error values and maximum rate of convergence is chosen as the best network for gas viscosity prediction. Results showed that the network with two hidden layers trained by the Levenberg-Marquardt training algorithm has an average absolute error of 0.001 for the training and validation data set. This network is chosen as the best network for prediction of gas viscosity using reduced temperature, reduced pressure and gas density as input parameters.

During and after drilling to the desired depth, the well completion step begins. One of the key parameters in a successful well completion is an effective cementing job. The quality of cementing job is strongly dependent on the removal of the drilling fluid, which already presents in the wellbore. Spacer fluids are used to remove the mud from the well before cementing the well. Different types of spacers are available in the oil and gas industry. When a high-pressure condition is expected along the cementing interval, high density or weighted spacers are used. Although they can resist the formation pressure by their high density, but they may have some trouble in an effective mud removal from the wellbore due to their high density and viscosity. In this paper an experimental study has been carried out to optimize the mud removal efficiency of weighted spacer systems. The experiments show that the proposed composition of the weighted spacer has a reliable removing ability, which makes it applicable for cementing operation in hostile conditions.

Hot gas injection in the gas assisted gravity drainage (GAGD) process in a fractured medium oil reservoir creates a hot gas invaded zone in the reservoir. Hence, the gravity drainage mechanism will improve and accelerate with hot gas injection effects on the oil viscosity reduction within matrix blocks of hot gas invaded zone and with increasing the density difference of this zone, therefore it leads to create a new process entitled ˝ hot gas assisted accelerate gravity drainage (HGAAGD) ˝. Simulation results show that HGAAGD process has more oil production rate, cumulative oil production, oil recovery factor and less gas-oil ratio (GOR) than the GAGD process.

Nowadays reservoir modeling and simulation are performed without considering mutual influence of equipments in surface facility. This will result in overestimating amount of produced oil in specified time period. The reason why this happens is that individual reservoir simulation has bottom hole pressure as controlling parameter but integrated reservoir simulation has controlling parameter of first stage separator pressure. In this paper, the effect of controlling parameters in integrated and non-integarated reservoir simulation has been explained. And then we compared results of these two cases in one Iranian field with two reservoirs. It was shown that non-integrated study has overestimated produced oil with respect to integrated one.

In this study, miscible gas injection methods have been investigated in Khesht oil field of Iran and actual data of the field is used to modeling process. For this study first EOS of the reservoir fluid was made by using PVTi simulator. Then slim-tube simulator is used in order to obtain MMP for both CO2 and Solvent gases. Then with respect to the obtained EOS which is provided by PVTi simulator, dynamic model of this field provided by using numerical simulator. After that the best scenario with respect to the highest oil recovery factor selected and the effects of both CO2 and Solvent gases compared at the same time. At the end the results of miscible gas injection project have been considered.

Water injection, gas injection or WAG flooding can have drawbacks such as increases in residual oil, introducing areas where oil sweeping does not occur and fluid segregation. Gravity segregation needs some time and distance to occur, so that the vertical conformance is good in places near the well and will be deterred as far from injected well. The size of these regions is principally related to injection rate, vertical permeability and density difference between water and gas. Furthermore, fluid injection has adequate length in which the vertical conformance is maintained. In IOR flooding processes it is essential to design a reservoir flooding that water-gas mixed the region is larger relative to the reservoir volume to be flooded by each well. This study benefits from prior associated researches to investigate the dominant factors controlling segregation around the injection wells and proposes a new analytic model for tilted reservoirs. The model has better prediction to the length of segregation rather than former models.

In-situ combustion is a high-risk thermal recovery which usually is used for heavy oil and extra-heavy oil reservoirs. This method of EOR can be done as forward and reverse which latter has been found economically unattractive and difficult to apply. In forward combustion, dry and wet can be used. This paper focused on dry combustion. A sensitivity analysis with a compositional simulator has been done. Effect of porosity of reservoir, permeability of reservoir, anisotropy ratio, initial temperature and target total molar rate was analysed on different key parameters. Water cut, oil recovery factor, gas oil ratio, total water production, well productivity index and reaction’s rate in the reservoir during combustion simulated for 600 days. It found that when permeability increased from 500 millidarcy to 1000, 3000 and 5000 millidarcy, GOR curve changed rapidly before first 90 days and shift to the lower values. Moreover, water cut decreased slightly and oil production increased from 15285 STB to 15768, 16648 and 18280 STB respectively. Furthermore, oil recovery factor and water production increased. Decreasing in porosity from 0.38 in BASE case to 0.30, 0.25 and 0.20 resulted in decreasing oil recovery factor, oil production from 15285 STB to 12180 STB, 10392 STB and 8709 STB respectively, water production and GOR. Increasing initial reservoir temperature from 200 °F to 250 °F resulted in increasing oil recovery factor from 0.85 to 0.95. In addition, it causes water start to produce sooner. Anisotropy ratio does not have any special effect on reactions, but changing initial temperature resulted in a considerable change in reactions. It proved that target total molar rate has a great effect on the oil production. In the BASE case, total molar rate of oxygen was 300 lbmol/day at 200F at 70psi and recovery factor was 0.85. By changing oxygen molar rate to 250, 100 and 70 lbmol/day at 200F at 70psi recovery factor changed to 0.95, 0.56 and 0.39 respectively. It concluded that optimum molar rate was 250 lbmol/day between these values.

In petroleum engineering, reservoir systems are described by highly nonlinear parameters. Accurate and fully-detailed simulations are very expensive and time consuming specially when uncertainty in material properties makes such systems even more complex. In order to account for uncertainty analysis, adequate high quality data sets are needed. Lacking these or a full reservoir simulation, proxy models are employed to work instead of a numerical simulator. They are employed in a wide range of workflows in petroleum engineering such as risk analysis, history matching, sensitivity analysis, reservoir characterization, field development planning, and process optimization. However, one important step in applying the proxy models is proper selection of effective parameters that have a major impact on reservoir performance. Analysis of Variance (ANOVA) can be applied to determine the effective parameters in proxy models. This paper aims to represents a novel method to choose effective parameters among various existing parameters as an input to proxy models. We use a design of experiment technique i.e. fractional factorial design to determine the effective parameters out of different existing parameters. Effective parameters chosen by this method may be further used as the only the input parameters into proxy models. Result show that three parameters become effective among eight. It is also observed that effectiveness of parameters is time independent for the studied reservoir.

One of the main concerns for reservoir engineers is prediction of future well performance. In hydraulically fractured wells flowing parameters completely change the governing equations of fluid flow through the reservoir and wellbore. Since the purpose of hydraulic fracturing is reduction of skin effect, this parameter plays the most important role in the future well performance. This paper introduces a new method for prediction of hydraulically fractured wells performance. This technique is based on using a new approach for skin effect parameter in hydraulically fractured wells. This method uses the concept of Part’s fracture relative capacity, without requiring knowing fracture and reservoir permeability or fracturing width. In this approach to convergence the fracture skin effect have derived a relation between fracture relative capacity and dimensionless fracture conductivity by using Cinco-Ley and Samaniego method. A program had been prepared to calculation of numerical equations governing on well flowing performance in the case of hydraulically fractured well through this study. At the end, this approach and developed code have been applied to the several fractured well fine grid black-oil simulation of a real oil reservoir. Finally, the simulation study confirmed the results of the proposed model and there was a reasonable agreement between the obtained results of proposed model and numerical simulator.

One of the main concerns for reservoir engineers is prediction of future well performance. In hydraulically fractured wells flowing parameters completely change the governing equations of fluid flow through the reservoir and wellbore. Since the purpose of hydraulic fracturing is reduction of skin effect, this parameter plays the most important role in the future well performance. This paper introduces a new method for prediction of hydraulically fractured wells performance. This technique is based on using a new approach for skin effect parameter in hydraulically fractured wells. This method uses the concept of Part’s fracture relative capacity, without requiring knowing fracture and reservoir permeability or fracturing width. In this approach to convergence the fracture skin effect have derived a relation between fracture relative capacity and dimensionless fracture conductivity by using Cinco-Ley and Samaniego method. A program had been prepared to calculation of numerical equations governing on well flowing performance in the case of hydraulically fractured well through this study. At the end, this approach and developed code have been applied to the several fractured well fine grid black-oil simulation of a real oil reservoir. Finally, the simulation study confirmed the results of the proposed model and there was a reasonable agreement between the obtained results of proposed model and numerical simulator.

Low salinity waterflooding is an emerging EOR technique in which chemistry play major role in improved oil recovery. Numerous laboratory tests from many research groups and some field applications confirmed its effectiveness in enhanced oil recovery. Various mechanisms have been suggested since its appearance to explain the mechanism of the process. Nevertheless, none of them could explain and predict all aspects of the process and possibility of enhanced oil recovery and yet, its mechanism is matter of debate. This paper provides a comprehensive review of low salinity waterflooding. Attempt is made to cover all aspects and features of low salinity waterflooding to shed light on critical and challengeable features and clear the gaps and deficiencies of conducted studies. The proposed mechanisms are discussed and their success and failure are explained. Analytical and numerical modelling of low salinity waterflooding is presented. Both approaches via conventional simulators and geochemical modelling are reviewed. The pore-scale investigation trend is also addressed as a new approach to unveil fundamental phenomena behind the process. Secondary and tertiary low salinity waterflooding are compared in the term of additional oil recovered. Surface forces and rock/fluid/brine interaction and its relationship to wettability are discussed. Results of study of combined low salinity and EOR methods are described which includes simultaneous use of low salinity with polymer flooding, surfactant flooding, CO2 flooding and also hot water injection. Field applications are demonstrated and necessary conditions to achieve low salinity oil recovery enhancement are discussed. Based on this review, it seems that multi ion exchange and double layer expansion both can contribute in oil recovery enhancement due to low salinity water injection. In fact both proposed mechanisms can reduce oil film thickness which in turn releases more oil. In fundamental point of view, any mechanism that alters surface forces (DLVO theory is starting point) can lead to oil detachment. The process not only is low cost in operation but also can reduce the amount of EOR agents (surfactant, polymer, etc..) and their effectiveness when it combine with other EOR techniques. Accordingly low salinity waterflooding-EOR methods have great potential for enhanced oil recovery in future.

Low salinity waterflooding is an emerging EOR technique in which chemistry play major role in improved oil recovery. Numerous laboratory tests from many research groups and some field applications confirmed its effectiveness in enhanced oil recovery. Various mechanisms have been suggested since its appearance to explain the mechanism of the process. Nevertheless, none of them could explain and predict all aspects of the process and possibility of enhanced oil recovery and yet, its mechanism is matter of debate. This paper provides a comprehensive review of low salinity waterflooding. Attempt is made to cover all aspects and features of low salinity waterflooding to shed light on critical and challengeable features and clear the gaps and deficiencies of conducted studies. The proposed mechanisms are discussed and their success and failure are explained. Analytical and numerical modelling of low salinity waterflooding is presented. Both approaches via conventional simulators and geochemical modelling are reviewed. The pore-scale investigation trend is also addressed as a new approach to unveil fundamental phenomena behind the process. Secondary and tertiary low salinity waterflooding are compared in the term of additional oil recovered. Surface forces and rock/fluid/brine interaction and its relationship to wettability are discussed. Results of study of combined low salinity and EOR methods are described which includes simultaneous use of low salinity with polymer flooding, surfactant flooding, CO2 flooding and also hot water injection. Field applications are demonstrated and necessary conditions to achieve low salinity oil recovery enhancement are discussed. Based on this review, it seems that multi ion exchange and double layer expansion both can contribute in oil recovery enhancement due to low salinity water injection. In fact both proposed mechanisms can reduce oil film thickness which in turn releases more oil. In fundamental point of view, any mechanism that alters surface forces (DLVO theory is starting point) can lead to oil detachment. The process not only is low cost in operation but also can reduce the amount of EOR agents (surfactant, polymer, etc..) and their effectiveness when it combine with other EOR techniques. Accordingly low salinity waterflooding-EOR methods have great potential for enhanced oil recovery in future.

Low salinity waterflooding is an emerging EOR technique in which chemistry play major role in improved oil recovery. Numerous laboratory tests from many research groups and some field applications confirmed its effectiveness in enhanced oil recovery. Various mechanisms have been suggested since its appearance to explain the mechanism of the process. Nevertheless, none of them could explain and predict all aspects of the process and possibility of enhanced oil recovery and yet, its mechanism is matter of debate. This paper provides a comprehensive review of low salinity waterflooding. Attempt is made to cover all aspects and features of low salinity waterflooding to shed light on critical and challengeable features and clear the gaps and deficiencies of conducted studies. The proposed mechanisms are discussed and their success and failure are explained. Analytical and numerical modelling of low salinity waterflooding is presented. Both approaches via conventional simulators and geochemical modelling are reviewed. The pore-scale investigation trend is also addressed as a new approach to unveil fundamental phenomena behind the process. Secondary and tertiary low salinity waterflooding are compared in the term of additional oil recovered. Surface forces and rock/fluid/brine interaction and its relationship to wettability are discussed. Results of study of combined low salinity and EOR methods are described which includes simultaneous use of low salinity with polymer flooding, surfactant flooding, CO2 flooding and also hot water injection. Field applications are demonstrated and necessary conditions to achieve low salinity oil recovery enhancement are discussed. Based on this review, it seems that multi ion exchange and double layer expansion both can contribute in oil recovery enhancement due to low salinity water injection. In fact both proposed mechanisms can reduce oil film thickness which in turn releases more oil. In fundamental point of view, any mechanism that alters surface forces (DLVO theory is starting point) can lead to oil detachment. The process not only is low cost in operation but also can reduce the amount of EOR agents (surfactant, polymer, etc..) and their effectiveness when it combine with other EOR techniques. Accordingly low salinity waterflooding-EOR methods have great potential for enhanced oil recovery in future.

It is widely accepted that different brines with various compositions can increase the oil recovery during water flooding in carbonate reservoirs. The concept of preparing a kind of smart water for these cases is an interesting subject whose underlying mechanisms have not been fully understood yet. It is still required to consider the crude oil/rock/brine interactions. To understand a typical smart water flooding process, it was decided to evaluate the effect of the two most important ions in a water flooding process. Calcium and magnesium, known as the hard ions, can be very effective, especially in the case of changing the reservoir rock surface behaviour and the fluids interactions. To understand these parameters, some solutions and carbonate rock samples were prepared; the fluids interfacial tensions (IFT) and the rock wettabilities were monitored by changing the ions concentration in aqueous phase. Contact angle measurement results showed that increasing the concentration of each of these ions can improve the water-wet tendency of the initially near oil-wet rock surfaces. This impact was more dominant for the case of having calcium ions. Interfacial tensions also reduced up to 20% while the concentration of these ions approached to that of typical carbonate formation water. The order of change for the case of calcium ion was more dominant (around 3%) than the other ion. The results of these experiments can be applied for real water flooding in carbonate reservoirs which are subject to the injection process, especially while the produced water is going to be used as the re-injecting agent.

Nuclear magnetic resonance (NMR) log provides the capability of reservoir characteristics measurement such as permeability, free fluid porosity (FFP) and bound fluid volume (BFV). Although this tool is one of the most important logs in reservoir characterization, there are some limitations i.e. it is impossible running this log in cased holes. On the other hand, due to high costs of NMR logging, a few wells in a field have this log. To overcome these issues, it will be needed a new method for generating NMR log synthetically. Since permeability and effective porosity are the two fundamental reservoir properties which have a significant impact on fields operations and reservoir management; current study presents, from a practical point of view, an excellent approach to synthesize permeability and FFP components of NMR log in a useful and fast manner and at a much lower price compared to the NMR logging practice. The presented methodology incorporates a back propagation artificial neural network (BP-ANN) as its main tool. The proposed methodology is presented with an application to field information of a carbonate reservoir, located in Persian Gulf, Iran. Validity of the results is checked through the comparison of synthesized values to real amounts of a set of data which is not included in development of the optimized ANN model and the correlation is presented. The results demonstrate that artificial neural network is an efficient and trustworthy way in synthesizing NMR components with an acceptable degree of accuracy.

Much research has been recently conducted on how to enhance oil recovery using a wide range of parameters. To this end, the three oil recovery mechanisms including primary, secondary and tertiary mechanisms have been improved and extended in order to increase oil production. One of the tertiary recovery methods that enjoys high popularity is water alternating gas (WAG) injection process. This method is applied in the reservoirs which are under natural depletion, and benefit secondary mechanisms such as water injection. The main object here is increasing the oil recovery. This method could benefit the advantages of both water injection and gas injection. Since the sweep efficiency of gas is less than water, the gas flow in the upper reservoir has a lower density, and if during the water injection process the water is not the wetting phase (since the water does not flow upper), much of the oil in the reservoir, which is trapped between the rocks, cannot be obtained. By the same token, we combined water injection and gas injection methods, benefited the advantages, minimized the disadvantages, and called it water alternating gas injection (WAG).

In this paper the temperature transfer in lumped system of combined convection-radiation in a slab made of materials with variable thermal conductivity is obtained. That is an important problem in Mechanics of fluids and in efficiency oil recovery (EOR) of petroleum reservoirs, when it is used of high explosive composites for EOR in petroleum reservoirs. In this paper the applicability and effectiveness of a new method that is used in recent years as a semi-exact analytical method is shown for solution of nonlinear boundary value problem. This method applied to lumped system arising in Heat transfer phenomena in in a slab made of materials with variable thermal conductivity then the results are compared with numerical solution and homotopy perturbation method (HPM), GA method and variational iteration method (VIM). This technique that is used in this work has this capability to find closed-form solutions of nonlinear problems and this method is easier to use and will be save in time.

In this paper the temperature transfer in lumped system of combined convection-radiation in a slab made of materials with variable thermal conductivity is obtained. That is an important problem in Mechanics of fluids and in efficiency oil recovery (EOR) of petroleum reservoirs, when it is used of high explosive composites for EOR in petroleum reservoirs. In this paper the applicability and effectiveness of a new method that is used in recent years as a semi-exact analytical method is shown for solution of nonlinear boundary value problem. This method applied to lumped system arising in Heat transfer phenomena in in a slab made of materials with variable thermal conductivity then the results are compared with numerical solution and homotopy perturbation method (HPM), GA method and variational iteration method (VIM). This technique that is used in this work has this capability to find closed-form solutions of nonlinear problems and this method is easier to use and will be save in time.

In this paper, a detailed study has been undertaken by considering Seismic, Geology, Geophysical/Petrophysical and Geochemical data acquired in the drilled wells in order to have good understanding on the geological set up for building the suitable petroleum system and reservoir characterization for optimum reserve estimation and economic exploitation of proven hydrocarbons. Lithostratigrahic and biostratigrahic correlations have been examined. Paleobathymetry, depositional environment, reservoir rock composition, source rock studies and pore pressure studies have been carried out in general considering the well data of few representative wells drilled in the Ramnad sub basin. The inferred lithology in Nannilam formation is feldspathic sands associated with montmorillonite, mica and mixed clay, where as in Bhuvanagiri, lithology is mainly calcareous sandstone associated with silt and clay minerals namely chlorite, kaolinite and mixed clay. Depositional environment in Bhuvanagiri and Nannilam formations is found to be marine and coastal respectively, and this may be due to variations in paleobathymetry levels at the time of sediment deposition. Source rock studies inferred that Andimadam shale is the source rock for Nannilam and Bhuvanagiri reservoirs. This is rich in organic content with early maturation. The pore pressure and temperature studies indicate that there is no high pressure and temperature zone in this area and hence drilling and logging can be carried out under normal temperature and pressure regimes. This study forms ground work for carrying out the detailed field study in each fields of the Ramnad sub basin that will enable for augmenting the estimated/proven hydrocarbon reserves, locating the bypass/left over/missed hydrocarbons and also providing suitable solutions for economic exploitation.

Oil production optimization is one of the main concerns of the reservoir management. In this regard, optimal location of wells can lead to a significant increase in the oil production. The purpose of this research is to investigate a new extension of the Automatic well-placement optimization technique maximizing the net present value (NPV) of the oil production. Since finding the optimal location of wells may require expensive and time consuming iterations through the reservoir simulator, we propose a deterministic (gradient-based) algorithm to address this issue. Our approach is consisted of searching the neighbourhood of the initial well which is called the pseudo-wells in order to find the optimal location of wells. Since these pseudo-wells inject or produce at a very low rate, they have a minor effect on the overall flow throughout the reservoir. In this work, we first calculate the gradient of NPV with respect to the flow rate in the pseudo-wells using an adjoint-based method. This helps us to find improving directions on the basis of which the optimal locations of wells can be determined. This searching method continues until no further improvement in the NPV is achieved. The main contribution to our work compares to last papers of Well-Placement, is that instead of using a fixed step size, a variable step size strategy is used which reduces the total convergence time. The method is applied to three waterflooding cases.

In conventional drilling, high mud weight can create a large overbalance pressure between the wellbore and reservoir. This overbalance can result in the invasion of mud filtrate, drilled solids and foreign fluids into the formation. Subsequently, this overbalance causes significant formation damage, and reduced productivity, thus requiring further costly stimulation operation. Underbalanced drilling (UBD) is a drilling operation in which the circulating drilling fluid pressure is less than formation pore pressure. Underbalanced technology may be very successful in decreasing or eliminating formation damage if properly executed. However, the advantage of UBD can be lost in case of short pulse overbalanced conditions or in case of spontaneous imbibition. During UBD, due to existence of capillary forces and wettability characteristic, especially in low permeable zones, the drilling fluid imbibes into the reservoir rocks in opposite direction due to the reservoir fluids and consequently formation damage can occur. Several parameters, e.g. pressure difference or exposure time, can affect the severity and magnitude of this kind of damage. The main goal of this study is determining the saturation profile of imbibed drilling fluid and consequently evaluating the magnitude of formation damage which occurs in underbalanced drilling. Four sandstone plugs with a single longitudinal fracture with open ends were used in experiments. The plugs were exposed to different experimental conditions to measure the effect of various parameters, e.g. exposure time and overburden pressure, on the severity of the damage. In the next step, the actual saturation profile of imbibed water was determined by the X-ray computed tomography (CT scan) technique. It is shown that for lower underbalanced differential pressure, higher exposure time and lower drilling fluid viscosity, fluid invasion will increase.

The tectonic evolution of a basin can hold vital information regarding the variations and changes in depositional environments. Sarawak basin has undergone strong tectonic activity in its past. In this study, a model has been proposed for the evolution of Tinjar and Balingian provinces in Sarawak, East Malaysia in order to throw light on tectonic events that was responsible for basin development. The model was developed by balancing and restoration of cross sections obtained from published interpreted seismic profiles. The model takes into account the subduction of proto-South China Sea oceanic crust beneath the Borneo plate during Middle Eocene to Middle Miocene. The resulting model depicts older sequences (T1S and T2S) were accreted on to Borneo continental plate as a wedge and younger sequences (T3S) as piggyback basins. Due to structural complexity and variability of the region, each tectonostratigraphic province of Sarawak should be analysed individually as the proposed model corresponds only to two provinces of Sarawak.