4D seismic has evolved from a qualitative tool to identify producing zones and bypassed oil, to become an integral part of quantitative reservoir management. Therefore, the 4D seismic is commonly expensive, feasibility study must be done on each region and/or field to examine whether the rock properties and fluid parameters let using seismic methods for reservoir monitoring or not. In this study which is done on a part of carbonate formation in southern Iran, using Kuster-Toksoz equations and Gassmann’s, seismic parameters variations due to changing fluid saturation in a well of carbonate oil reservoir, are calculated. Then by using of Aki-Richard equation, synthetic seismograms for before and after oil production are generated. Consequently, time lapse seismic method could be accomplished on this oil field.

There is a lag time before the reservoir starts contributing through the sand face when a well is opened for production. The sand face flow rate does not go to zero instantaneously as the well is shut in. During this time lag the flow rate is called well bore storage for a production and shut in period. Distinguishing the end of well bore is one of the most significant challenges in well test analysis. De-convolution which is the conversion of a variable rate distorted pressure profile in to the pressure profile for an equivalent constant rated production sequence can be used to this job. Beta De-convolution method has been applied in one Iranian naturally fractured reservoir to predict the end of well bore storage. The pressure data were best matched with a dual porosity model. The pressure data were analysed for two cases of not using the beta de-convolution method as well as for the case of using this approach to eliminate the distorted pressure data. The results show that the calculated well bore storage coefficient, permeability, interaction coefficient, storability ratio and skin factor for the second case has about 185%, 10%,-11%, -15% and -7 % difference with the case of not using this approach.

Even after primary and secondary recovery processes have been completed still large quantity of the oil still lays trapped in the reservoir. This trapped could be either oil residual or by-passed oil. Residual oil occurs as a result of high capillary action of water that keeps the oil immobile. One way of recovering this capillary trapped oil is by flooding the reservoir with surfactants. Surfactants are surface active agents that act on the interface between oil and water with the aim of reducing the interfacial tension between them.There by causing trapped oil to flow. As the increasing water cut and reduced oil production it becomes obvious that water flooding alone cannot recover the oil effectively. Thus use of enhancing agent is like surfactant is one of the solutions. When flooding take place in reservoir with surfactants, with the right quantity that would yield the maximum recovery without unnecessary waste of the surfactant because of the high cost.In this paper the effects of Triton X-100, on the reduction of interfacial tension (IFT) between brine and oil sample obtained from fracture carbonate reservoir was studied at the reservoir temperature. The result showed maximum reduction on the interfacial tension between oil and water at a concentration of 0.8 wt% of Triton X-100 was occurred.

Point of zero charge (PZC) is defined as the PH at which a solid surface submerged in an electrolyte, exhibits zero net charge. Previous studies have reported different values of PZC for carbonate and sandstone rocks, mostly utilizing the electrophoresis technique. The aim of this study is to investigate and verify the PZC of carbonate and sandstone rocks. The PZC measurements were conducted in various brine salinities. Voltage measurements were recorded at a sampling rate of 1 Hertz by the National Instrument Data Acquisition System, using LabVIEW software. The PZC for both carbonate and sandstone rocks has been observed in the range of 9.40 to 9.70 and 2.2 to 2.9 respectively. As streaming potential measurement has been proposed to monitor water encroachment, having the understanding of PZC value will enable the signal to be interpreted more accurately. As a result, water encroachment issue will be overcome efficiently.

Extensive laboratory studies have now indicated that oil recovery in water flooding is dependent on the chemistry of the injected water. In this work, core flood experiments were performed to investigate the effect of injected water and crude oil chemistry on the oil recovery to further understand the low salinity waterflooding process. Two types of test oils were used to saturate the cores: a) Oil–A with acid number (AN) of 0.842 mgKOH/g, and b) Oil–B acid number of 1.683 mgKOH/g. The flooding experiments were performed by successive injection of formation brine, low salinity water, and surfactant/alkaline improved low salinity water. The results showed that low salinity water injection improved the oil recovery by 4-22 % of OOIP in a tertiary mode. Adding small amount of surfactant to low salinity water (dFW0.01+ 1 wt% SDS) increased the recovery by 22% of OOIP. The effect of surfactant was discussed in terms of reduced surfactant adsorption on the rock surface, improved wetting condition, and lowered interfacial tension (IFT). Alkaline solution also improved the promising effect of low salinity water about 12.3% of OOIP. The increased recovery by alkaline was attributed to the in-situ saopinification and wettability modification. It was concluded that combination of low salinity water with surfactant or alkaline had significant effect on boosting the effect of low salinity water flooding. The observations emphasize the potential of low salinity water as the make–up water for the chemical enhanced oil recovery (EOR) processes.

CO2 injection has been used for many years and it is accepted as a beneficial tertiary recovery method. However, there are very limited studies of liquid CO2 injection process and its effect on reservoir properties. The objective of this research is to investigate the effects of liquid CO2 injection on temperature distribution, fluid properties and oil recovery in a high temperature reservoir. A thermal compositional model is used to simulate the behavior of the reservoir in terms of viscosity, front movement and temperature. The main results of the study show that the temperature of the reservoir is affected by injection temperature and its rate; also, the effect of low temperature on viscosity cannot eliminate viscosity reduction by CO2. The recovery is doubled (12.81% increase) and mainly is due to liquid CO2 viscosity reduction by 6 times.

It is becoming more and more common to use assisted history matching methods to find different combinations of reservoir simulation models that agree with production and time lapse seismic data if exists. Models with a large number of cells contain millions of unknown parameters and selecting the correct values can be difficult. In practice not all are important but finding which parts of the reservoir require updating can be difficult. In this work we investigate methods of history matching by focusing on sub-volumes of the parameter space and we use streamlines to help us choose where the model requires change. We identify localities in the reservoir that affect particular wells and we update reservoir properties (net:gross and permeability) within. We control changes using the pilot point method combined with a Neighborhood Algorithm.We first apply these approaches for production history matching of the Nelson field where uncertainty of the shale distribution controls predictions. The field is divided into localities based on the performance of the worst well predictions. We then extend the application to a more complex case including both production and seismic data in history matching. The localities that require change are sufficiently separate that we can modify them one at a time. We also compare our result with a more ad hoc approach where the whole area around the well is modified. We find that, for the wells of interest, the streamline guided approach gives a 70% improvement in the history match from our starting model and around 40% reduction of misfit in prediction. This improvement is twice that of the total area approach. The streamline approach has been applied successfully for seismic and production history matching of Nelson that makes 50% and 35% improvement of well production in history and prediction periods and 10% improvement of seismic map compared to the base simulation model.Reservoir simulation and history matching are crucial for reservoir management especially when developing field management plans. By application of a good updating workflow in the right area of the model through an automatic history matching process we have gained a greater insight into reservoir behavior and have been able to better predict flow from simulation models.

The study of depletion performance of gas condensate reservoirs has gained wide interest in petroleum industry during the last few decades and poses a challenge for the reservoir modeller. Upon depletion, falling the reservoir pressure below the dew-point of hydrocarbon mixture results in liquid condensation at reservoir conditions. This liquid may be temporarily or permanently trapped in the reservoir causing severe reductions in gas production rates and the permanent loss of a large portion of the volatile and valuable condensates. This becomes highly noticeable for the case of tight reservoirs (less than 10 md). Hence, it is critical to answer this question whether this trapped hydrocarbon has been irreversibly lost or not. It is believed that the interplay of Darcian-type flow and Fickian type flow (multi-mechanistic flow) is the key to answering this question. Therefore as the first goal of this study, by utilizing a compositional simulator (ECLIPSE 300) and modelling a synthetic reservoir with the fluid of one of the Iranian gas-condensate reservoirs; we try to assess the role of multi-mechanistic flow on the condensate appearance for the permeable (50 md) and tight (5 md) reservoirs. On the other hand, since gas injection/cycling is a main recovery process for preventing loss of valuable condensates, the methodological plan of this study is to do a sensitivity analysis on various gas injection/cycling scenarios in the reservoir at pressures below the dew point (maximum condensate appearance).

Coiled tubing (CT) has been used in well drilling, completion, stimulation, wellbore cleanout, and other operations in the petroleum industry where various fluids are pumped under turbulent flow conditions. Accurate estimation of frictional pressure losses when pumping these fluids through coiled tubing has remained a challenge and a milestone for job success. This challenge has triggered the research activities in the field of coiled tubing hydraulics. As a result, there have been extensive studies on flow of Newtonian fluids in coiled tubing and several equations have been published to calculate the Fanning friction factor. Each of which has its own applications and limitations. Applications of these equations without verification may lead to erroneous results, and eventually job failure. Employing the new Akaike Information Criteria or AIC theory, the authors compared and questioned the applicability of these correlations to propose the most accurate one. This study employs the R^2 method and the Information Theory Approach in selecting the best model to predict the Fanning friction factor. It shows that among six different models, the best model to predict the Fanning friction factor is McCann and Islas model and the weakest one is Mashelkar and Devarajan model. A comparison between R^2 and AIC theory is also presented to show the advantages of AIC theory over R^2 method. In conclusion, the authors are introducing a new theory to the oil and gas industry where they believe that employing this theory can resolve various difficulties faced by the researchers in the oil field. This paper represents the first application of AIC theory in the oil and gas theory and helps advances the state-of-the-art in this field.

In this paper a survey of modeling and simulation of matrix acidizing in sandstone formations and development of matrix acidizing simulator is investigated. The models used in acidizing of sandstone formation are recognized and one of the most important related models have been coded in such a way that equations covering this model and the stages of making the simulator is explained. In the end, by using simulation software, operations of characterizing of the formation as mineralogy, matrix acidizing, influences and parameters of design such as injection rate is investigated. The most important sandstone acidizing design parameters are acid injection rate, formulation and type of injected acid, volume of injected acid, volume of fluids used in after/before the injection. Computer simulation is performed as a way to investigate the influences of some factors on the result of acidizing operations and injecting fluid behavior and how to fix the damage from the wellbore for different values of these factors, Such as type of damaging material, percentage of formation mineralogy compound, damage intensity and its radius. Developed simulator can be applied to a number of these investigations.

Matrix acidizing is a stimulation technique commonly applied to sandstone reservoirs to remove near wellbore skin damage and improve well productivity. For any acidizing process, the selection of acid (formulation and concentration) is very important. Mud acid has been successfully used to stimulate sandstone reservoirs for a number of years. It is a mixture of hydrofluoric (HF) and hydrochloric (HCl) acids designed to dissolve clays and siliceous fines accumulated in the near-wellbore region to re-open or enlarge microscopic flow paths and thus improve formation permeability. The success of acidizing depends to a great extent upon proper acid selection and good treatment design. There are mainly three stages in acidizing process i.e., pre flush, main acidizing, after flush treatment. The results of acidizing depends on all these stages. For effective acidizing process best acid combination should be used in these stages to ensure that the permeability and porosity change is maximum. In this paper combinations of (HCl and CH3COOH) had been used and compared with the standard acid combination (15% HCl for the pre flush stage). As this stage is the initial stage and the main function of the acid should be to remove the carbonates present in the formation and also to remove the Na and K ions.

This paper has reviewed the geomechanical studies and their applications in petroleum engineering. Geomechanical studies are applied in the wellbore and reservoir to establish the stability, which is a major problem in oil and gas industry. Most of studies are concerned with the drilling operations, however production operations and enhanced oil recovery (EOR) methods also alter the wellbore and reservoir stresses. It may cause problems such as collapse, sand production and fracture in the wells. Many researchers have tried to model the stress in the borehole in more than fifty years. They have governed various equations to investigate the flow, thermal and chemical effect in stress distribution. They have done their studied for many different conditions in different flow phases. In order to define the stability conditions, different failure criteria have been introduced. Many stability studies have been implemented using these criteria. The stress analysis should be coupled with reservoir simulation. During the lifetime of the reservoir, the change in stress could lead to the failure, so its effect should be studied on the field stability. However, there are lots of reservoir studies that did not consider geomechanics.

Mathematical models of petroleum reservoirs have been utilized since the late 1800s. A mathematical model consists of a set of equations that describe the flow of fluids in a petroleum reservoir. In this paper the applicability and effectiveness of a novel iterative method as a semi-analytical method is shown for solution of partial differential equation that model porous medium. This nonlinear partial differential equation describing instability phenomenon of two immiscible fluids (water and oil) flow through homogeneous porous cylindrical medium with impervious bounding surfaces on three sides of an oil reservoir. This method applied to a porous medium equation arising in instability phenomena in double phase flow through porous media. Furthermore, this technique is utilized to find closed-form solutions for the problem under consideration with appropriate initial/boundary conditions.

The petroleum industry welcomes new technologies that not only increase production rate effectively but also minimize the formation damage. The energy required to remove a unit volume of rock, namely the specific energy (SE), is a critical rock property data that can be used to determine both the technical and economic feasibility of laser oil and gas well drilling. When a laser beam is applied on a rock, it can remove the rock by thermal spallation, melting, or vaporization depending on the applied laser energy and the way the energy is applied. Our experiments showed the most efficient rock removal mechanism would be the one that require the minimum energy to remove a unit volume of rock. This paper will present study results on using a pulsed CO2 laser to drill through the given rock samples. Preliminary test shows that CO2 laser can drill the rock as efficiently as the other types of high power lasers and the permeability of the rock lased by pulsed CO2 laser beam increases up to 150% compared to non-lased rocks due to clay dehydration and microfractures induced by the high temperature gradient and phase transformation volume expansion generated in the rock while lasing.

The petroleum exploration industry is cost intensive and requires detailed risk and economic evaluation of prospective areas to promote adequate investment. The objective of this study is to demonstrate the methodology (workflow) involved in assessing the potential profitability of a prospect using the GeoX software. The Nordkapp Basin of Norwegian section of the Barents Sea was used as a case study. The three stage evaluation approach applied in this study comprises risk evaluation of petroleum system elements, estimation of hydrocarbon volume and economic assessment of forecasted revenues from the sale of oil and gas. The results showed that geologic risk evaluation is an important input for volumetric estimates, which in turn is one of the main input parameters of the economic assessment. In addition, all three stages of the evaluation need to be carried out for an effective decision to be made on whether to drill a prospect.

The reservoir under study is a reservoir with high amount of H2S and asphaltene. It has more than 1 billion of Original oil in place as static geological model estimated but the problem is the only drive mechanism is Solution gas drive and it has no active aquifer so although it had good flow potential but what if it drops lower than bubble point pressure? Dynamic model showed it was to deplete quickly. By using new reservoir management techniques and enhanced oil recovery in order to pressure maintenance one can recover a lot more oil. The scope of this project was to evaluate in terms of impact of surface facilities, reserves and recovery factor of using gas injection and then different fluid composition for this field’s gas injection (Rich gas corresponding to the associated separator gas to be re-injected to reservoir & Lean gas corresponding to the associated separator gas to be re-injected to reservoir after condensate removal). There are 40 wells in this fields and this was possible to change function of production well to injector if needed. After comprehensive study and technical evaluation it was found that. Miscible gas injection was the best scenario to Natural depletion.

Foam is non-Newtonian pseudo-plastic fluid, which is used for drilling, well intervention, and stimulation. Predicting the cutting transport efficiency of foam in the wellbore annulus is very important to optimize the drilling process. In this paper, the cuttings transport process with foam is numerically simulated using an Eulerian two-phase model in inclined wellbores. A Computational Fluid Dynamics (CFD) software package called FLUENT was used for this goal. The effect of foam quality, foam velocity and drill pipe rotation on cuttings transport phenomena in both concentric and eccentric horizontal annulus was investigated. The simulation results are compared to the experimental data from previous studies, with a relative error less than 8%. This study shows the reliability of the CFD simulation in replicating the actual physical process.

Shale gas production has been increasing rapidly in the past few years due to its potential as a huge resource. However, since shale gas reservoirs have very low permeabilities, there is a great challenge for an economic large scale shale gas production. Knowledge of the effects of influential factors on shale gas production can make us have a better understanding of how shale gas can be effectively and efficiently produced from the shale gas reservoirs, which can help us design an economic development plan for shale gas production. In this paper, a simulation based method is used to investigate the effect of several influencing factors such as well orientation, penetration length of horizontal well, natural fracture permeability and hydraulic fracture permeability on shale gas production. The simulations show that in the simulated period, the gas production rate and total gas production of the horizontal well (HW) are much higher than those of vertical well (VW). Further simulations show that in the simulated period, the gas production rate increases with increasing the penetration length of horizontal well in the beginning, even though the total gas production is the same. Further simulations also show that in the simulated period, the gas production rate increases with increasing the natural fracture permeability and hydraulic fracture permeability in the beginning, even though the total gas production is the same.

This work aimed at the use of regression method to develop Condensate gas ratio (CGR) correlations using data set obtained from Eastern Niger Delta region. The procedure of dividing the formation into three distinct geologic zones was adopted. These zones are: Transitional Paralic, Paralic and Marine Paralic zones. The basic parameters used for the correlation development are: reservoir depth (ft), reservoir pressure (psia); reservoir temperature (oF) all at Gas – Oil – Contact ( GOC) / Gas – Down – To (GDT) / Gas – Water – Contact (GWC) and these parameters are obtained from the field data. Matlab and Excel softwares packages were used as the implementation platform. Both quantitative and qualitative assessments were employed to evaluate the accuracy of the new correlations to the experimental values. The models have very impressive statistical parameters with good ranks and better performance plots. The correlations developed among others considerations form a strong technical background for booking of gas-condensate reserves.

The production optimization is the key to increase the total production. However, proper production scenario is resulted from the complete reservoir model. The reservoir condition is the clue to find the best production method. This paper had summarized the different studies of gas lift and ESP installation for real field data and compared it with the result of water and gas injection simulation. Different cases of production planning (including new infill wells, modification in reservoir simulation and etc.) had been done for next 40 years of the field life.

Compressional and Shear velocity are two fundamental parameters which have many applications in petrophysical, geophysical, and geomechanical operations. These two parameters can be obtained using Dipole Sonic Imaging tool (DSI), but unfortunately this tool is run just in few wells of a field. Therefore it is important to predict compressional and shear velocity indirectly from the other conventional well logs that have good correlation with these parameters in given well without these logs. The overriding tool of this work is intelligent systems including Artificial Neural Network, Fuzzy Logic and clustering tool Multi-resolution graph-based clustering (MRGC) for prediction of Compressional and Shear velocity. In this paper 1328 data points from one formation which have Compressional and Shear velocity are used. These data are divided into two groups: 998 data points for construction of intelligent systems, and 330 data points used for model testing. The results showed that despite difference in concept, all of the intelligent techniques were successful for estimation of Compressional and Shear velocity but clustering tool is better than other method.

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.

Porosity is one of the fundamental petrophysical properties which should be evaluated for hydrocarbon bearing reservoirs. Petrophysical well logs are the most essential instruments for the evaluation of hydrocarbon reservoirs. There are three main petrophysical logging tools for porosity determination namely: neutron, density and sonic well logs. Porosity can be determined using each of these tools; however, a precise analysis requires a complete set of these tools. Log sets are commonly either incomplete or unreliable for many reasons (i.e. incomplete logging, measurement errors and loss of data owing to unsuitable data storage). To overcome this issue, the current study presents an intelligent technique using Artificial Neural Networks (ANN) to synthesize petrophysical well logs including: neutron, density and sonic logs. To accomplish this, the petrophysical well logs data collected from six wells was utilized for constructing optimum ANN model and a seventh well data from the field was employed to evaluate the reliability of the model. The proposed methodology is presented with an application to field information of a carbonate oil reservoir, located in Persian Gulf, Iran. The corresponding correlation was obtained through the comparison of synthesized log values to real log amounts. The results demonstrate that ANNs are successful in synthesizing petrophysical well logs with a high degree of accuracy.

Shale gas is an unconventional type of natural gas; having the same composition as a conventional one, but produced from low permeability sediments and rich in organic matter. In shale gas natural fractures can usually do not provide adequate pathways for sufficient flow of hydrocarbons into a well and because of their low permeability, they are rarely economic. Now production of shale gas is currently possible where shale is fractured. Natural gas from shale is developed using horizontal drilling and multi-stage hydraulic fracturing. Horizontal drilling is used to provide greater access to the gas trapped in the producing formation. Hydraulic fracturing pumps fluid (water with a small amount of additives) and sand or other proppants down along the well at high pressure. The pressure causes the surrounding brittle rock to fracture. Hydraulic fracturing can significantly increase the yield of a well. When it is combined with horizontal drilling, unprofitable and uneconomical rock formations are often converted into productive natural gas fields. In this paper we initially describe shale gas, properties needed for economical shale gas production, shale gas reservoirs evaluation and its production methods. Finally we lead and end shale gas topics to Iran and describe shale gas in Iran.

Composite pressure vessels (CPV) are used for large commercial and industrial applications such as softening, filtration and storage. In this study, the design of composite pressure vessels based on “unit load method” along with complete structural analysis and evaluation of additional parameters are performed using finite element commercial code ANSYS. “Unit load method” covers many of the weaknesses of traditional methods and carries out more detailed design using many factors that composite materials provide for designer. The FEM results are compared with experimental ones and a good agreement between them is noticed. By increasing the vessel pressure acceptable and appropriate behavior is observed in strain-pressure curves. As a result, the proposed method can be implemented with acceptable confidence and less cost for comprehensive design of composite pressure vessels.