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Depression is a mental illness with several categories that have common symptoms such as chronic sorrow, lack of interest, lack of pleasure, mood swings between guilt and poor self-esteem, sleep disturbances, and a loss of appetite. Over 300 million individuals globally suffer from depression, and the socioeconomic cost of this debilitating disorder is expected to rise dramatically in the future decades. Behavioral health illnesses can be prevented and treated to some extent with dietary and nutritional means. Nutritional psychiatry has produced observational and effectiveness evidence regarding the role of healthy dietary patterns in the onset and treatment of depressive symptoms. Diet is associated with depressive symptoms or depression, meaning that an increase in depressive disorders coincide with a deterioration in healthy living choices, including poor quality diets. Healthy eating habits and adequate intake of essential nutrients via the diet can help prevent and treat depression by reducing symptoms of mental illness. In addition, because nutrition is a modifiable risk factor for depression, it is practical for the public to consider dietary changes to reduce the prevalence of depressive disorders. This paper reviews the potential value of diet-based actions to manage depression, and ways in which dietary changes could be made to improve mental and cognitive health. Furthermore, some practical solutions for preventing and controlling depression are proposed based on health-related effects of improving dietary habits and life style.

The necessity for higher speed and appropriate seakeeping performance of boats has led to extensive research. Hence, this research mainly discusses the optimal behavior of the boat against motions. From an economic point of view, reducing motions of the boat minimizes the damage caused by shock and vibration to the boat and equipment. Other benefits include comfort and safety and, as a result, improved human operating ability. Suspension systems are rarely used as motion controller in a boat. In multi-hull boats, the hull is an inseparable part of the vessels, so the wave will affect crew and equipment. This paper proposes and evaluates a novel concept boat equipped with a suspended cabin. The hull and superstructure (cabin) are separated in this new form by a simple passive suspension system. This study used numerical analysis to examine the seakeeping performance of the planing boat Fridsma model equipped with a passive suspension system under regular wave conditions. The hydrodynamics of the planing hull were modeled using commercial software, STAR-CCM+. For simulation of the passive suspension system between boat and cabin, MATLAB software was used. Results showed that the motion of the cabin, which is where the crew and equipment are located, decreased in regular waves.

Purpose This study aims to systematically review the economic complexity literature to advance the knowledge on its contribution to building regional competitiveness. Design/methodology/approach In this study, we did a systematic review of 111 relevant papers. In this regard, we did a thematic analysis on all the collected papers, which led to a two-level processed approach. In the first level, the contributions of the reviewed articles have been classified into three main streams. In the second level, the findings under each contribution category are analyzed and explained. This approach led to a thematic network demonstrating economic complexity and the dynamics of regional competitiveness and a set of managerial and policy implications. We followed a multiple processed approach for the systematic review of 95 papers that reveals considerable contributions in three categories, including measurement techniques, criticisms and exploratory studies. Findings Despite some critiques and the undertaken evolution in measurement techniques of complexity, economic complexity has become a well-known method mainly for regions' competitiveness dynamics. Our review demonstrates a nested network of economic complexity dynamics that drives policy advice concerning countries' status in their development path. The provided set of policies includes guidelines for underdeveloped and developing countries and general policy implications, applicable for all regional contexts for building competitiveness dynamics. Originality/value This research contributes to the literature on competitiveness from the window of economic complexity. The study allows a deep understanding of regions' productive structure role in their development and competitiveness. A set of policies for building regional competitiveness is provided concerning the study's findings. The literature gaps are identified, and future research ideas are provided for using economic complexity methodologically and logically to boost regional competitiveness.

Purpose To compare the efficacy of local ozone injection versus corticosteroid in plantar fasciopathy treatment. Patients and methods This double-blinded randomized trial was performed on 44 adult patients with plantar fasciopathy. One group (23 patients) received local injection of 40 mg methylprednisolone, while a local injection of 3 cc oxygen-ozone solution was performed for the other group (21 subjects). Severity of pain, functional level, and pressure-pain threshold (PPT) were measured before treatment and 1, 4, and 12 weeks after injection using VAS, Foot and Ankle Ability Measure (FAAM) questionnaire, and algometer for PPT, respectively. Results The majority (65.9%) of the total 44 patients analyzed, were women. Both treatments efficiently relieved patients' pain and improved their functions at 1 and 3 months follow-up time-points. But one week after injection, the improvement in VAS (p 0.05). Nevertheless, both methods efficiently improved patients' symptoms, ie, over the 50% of pain reduction and 30% improvement in functional status. Conclusion The present results showed no remarkable superiority between the two groups. In other words, although ozone injection showed a slower efficacy than methylprednisolone, it could be used in plantar fasciitis management as an appropriate alternative.

In some quality control applications, processes consist of multiple components, stations or stages to finish the final products or the services. Some quality characteristics in each stage of these ...

Low efficiency of somatic embryo maturation, germination, and conversion to plantlets is a major problem in many species including J. regia L. Germination efficiency of somatic embryos is very low in walnut. In this study, effects of two carbohydrate sources, sucrose and maltose (each at 3% and 6%), and two kinds of PEG (4000 and 6000) (each at four levels of 1.5%, 3%, 5% and 7.5%) on maturation and germination of walnut embryos were tested. The number of somatic embryos increased conspicuously on medium containing PEG. Furthermore, higher levels of PEG-4000 (7.5%) could remarkably enhance the morphogenesis of somatic embryos and the number of embryos produced. PEG-4000 stimulated somatic embryo maturation of walnut. This stimulatory effect was dependent on the carbohydrate source used. Sucrose in combination with PEG-4000 produced 50% of cotyledonary and normal somatic embryos. Different concentrations of PEG were effective on the number of embryos with a shoot meristem. PEG-4000 7.5% and sucrose 3.0% produced the highest rate (50.0%) of normal shooting embryos. However, PEG (4000, 6000) and maltose caused an unfavorable effect and increased the frequency of abnormal shaped somatic embryos.

Hydraulically fractured tight gas reservoirs are one of the most common unconventional gas sources being produced today, and will be a regular source of gas in the future. The extremely low permeability of tight gas sands leads to inaccuracy of conventional build-up and draw-down well test results. This is primarily due to the increased time required for transient flow in tight gas sands to reach pseudo-steady state condition. To increase accuracy, well tests for tight gas reservoirs must be run for longer periods of time which is in most cases not economically viable. The large amount of downtime required to conduct well tests in tight sands makes them far less economical than conventional reservoirs, which leads to the need for accurate simulation of tight gas reservoir well tests. This paper presents simulation results of a 3-D hydraulically fractured tight gas model created using Eclipse software. The key aims are to analyze the effect of differing fracture orientation, number and length. The focus of the simulation runs will be on the effect of hydraulic fracture orientation and length. The results will be compared to simulation runs without the abovementioned factors to determine their effects on production rates and well performance analysis. All results are plotted alongside an un-fractured tight gas scenario in order to put the hydraulic fracture performance in perspective. Key findings from this work include an approximately linear relationship between initial gas rate and the number of hydraulic fractures intersecting the wellbore. In addition, fracture length is found to have less of an impact on initial gas rate compared to number of fractures intersecting the wellbore, for comparable total fracture volumes.

Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation operations. Therefore they may not produce gas at commercial rates without production optimization and advanced completion techniques. Tight formations have small pore throat size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Leak-off of liquid from the wellbore into the formation may damage near wellbore permeability due to water blocking damage and clay swelling, and it can significantly reduce well productivity even in hydraulically fractured tight gas reservoirs. This study presents evaluation of damage mechanisms associated with water invasion and phase trapping in tight gas reservoirs. Single well reservoir simulation is performed based on typical West Australian tight gas formation data, in order to understand how water invasion into the formation affects well production performance in both non-fractured and hydraulically fractured tight gas reservoirs. A field example of hydraulic fracturing in a West Australian tight gas reservoir is shown and the results are analyzed in order to show importance of damage control in hydraulic fracturing stimulation of low permeability sand formations. The study results highlight that water blacking can be a major damage mechanism in tight gas reservoirs. In water sensitive tight sand formations, damage control is essential and the well productivity improvement may not be achieved in the case of excessive water leak-off into formation during hydraulic fracturing operations.

Objective: Communication between the median and ulnar nerves in the forearm (Martin-Gruber anastomosis) proved by anatomical and nerve conduction studies. The knowledge of these anastomosis is of major importance for assessment of traumatic or entrapment lesions of the median and ulnar nerve. Thus the prevalence of Martin-Gruber anastomosis (as the main purpose) must be determine in any population. The present prospective study was made in Shohada-e-tajrish hospital in 2002. Materials & Methods: Data were collected from 212 arms tested for carpal tunnel syndrome, compression ulnaropathy, polyneuropathy to exclude abnormalities. Supramaximal stimuli were given at distal and proximal sites of the median and ulnar nerves. Bar electrodes on define sites were used to record CAMP from thenar, first dorsal interosseous and hypothenar muscles, with stimulation of median and ulnar nerves. Diagnostic criteria for MGA have been proposed:1.CAMP over A.P.B higher in elbow than on wrist stimulation of median nerve. 2. CAMP over A.D.M. higher significantly on wrist than elbow stimulation of ulnar nerve.3.Recording of negative CAMP over A.D.M. of F.D.I. on elbow stimulation of median nerve ( not at wrist). Results: The study comprised 212 arm(50% left,50% right). The mean age of patients was 26 years (range:15-45years) 52 were women . Eleven subjects has MGA (Prevalence: 10.3%). The sex ratio was 7 females to 4 males. Conclusion: According to the method of our investigation the prevalence of MGA were 10.3% . More recently nerve conduction studies stated a prevalence of 31-34%. In our study the comparatively small prevalence of MGA must be documented by other studies in our populations.

We designed a randomized clinical trial with control group, to investigate the effects of platelet rich plasma (PRP) on pain, stiffness, function and quality of life in patients with knee osteoarthritis. Patients were randomly divided in two groups. For both groups of participants, therapeutic exercise was prescribed. In the PRP group, two courses of leukocyte rich PRP (5.6 fold higher platelet concentration) with a 4-week interval was injected. For each participant, Western Ontario and McMaster University’s Arthritis Index (WOMAC) and the SF-36 questionnaire (Farsi version) were filled at the baseline and 6 months after treatments. Thirty-one patients in the PRP group and 31 patients in the control group were studied. Mean changes of total WOMAC, physical component summery and mental component summery of Short Form-36 in PRP group showed better improvement than control group (P

The low permeability and tight gas reservoirs are problematic throughout of their development (drilling, completion, stimulation and production) around the wellbore. However, they required advanced improvement techniques to achieve flow gas at optimum rates. Phase Trapping or retention of fluids is a form of mechanical formation damage mechanism, which is caused by fluid invasion into formation, and also when liquid leak-off into formation during fracturing stimulation near the wellbore. Low permeability and tight gas reservoir are sensitive to water invasion damage results create water blocking and phase trapping damage due to high critical water saturation, relative permeability effects, capillary pressure and Interfacial tension between produced fluid and wellbore fluid. Proper evaluation of damage and its factors which influenced its severity is essential for prevention and optimizing well productivity. Thus, this study is presenting both laboratory experiments and simulation to evaluate phase trapping damage. In which, the core flooding was performed to evaluate permeability damage by using Malaysian diesel-oil drilling fluid in comparison with water based drilling fluid. Further, interfacial tension was tested between produced gas and wellbore fluids at different temperature and pressure conditions. The effect of interfacial tension on phase trapping damage was observed and validate with the result of core flooding experiments where the affect of water injection and diesel-oil injection on core permeability was studied and shown. Reservoir Simulation approach was also used to study the effect of relative permeability curves on phase trapping damage and its impact on well productivity. The result highlights the benefits of using Malaysian diesel-oil in drilling and fracturing the low permeability and tight gas reservoirs in meaning of 30% increment in well productivity compared with water based fluid.

Welltest interpretation requires diagnosis of reservoir flow regimes to determine the basic reservoir characteristics. In hydraulically fractured unconventional oil and reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, and also heterogeneity and complexity of reservoir. Thus, use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, transient analysis techniques that utilize higher order pressure derivatives integrated with rate transient analysis (RTA) can reduce uncertainties associated with welltest analysis and provide better estimate of the reservoir and hydraulic fractures dynamic parameters. This paper illustrates the reservoir flow regimes in non-fractured and hydraulically fractured unconventional reservoirs, proposes welltesting and interpretation methodologies, and presents field examples in order to show how the hydraulic fracture size and the permeability of the stimulated reservoir volume can estimated for hydraulically fractured unconventional gas reservoirs.

Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.

Wireline formation testing and measurement of true formation pressure can provide essential knowledge about the reservoir dynamic characteristics. In tight formations, a reliable determination of pressure and mobility gradients is challenging because of the tight nature of formation rock. Due to the very low reservoir permeability, the mud cake across wellbore is often ineffective in preventing filtrate invasion, thus causing the measured pressure to be higher than actual formation pressure as a result of supercharging effect. Wireline formation testing measurements are also influenced by the effects of filtrate invasion and capillary pressure, as the measured pressure is pressure of drilling fluid filtrate, the continuous phase present in the invaded region around wellbore. As a result, the measured pressure might be different to true formation pressure. This effect is more noticeable in tight gas reservoirs due to capillary pressure effect.This paper looks into estimation of true formation pressure and evaluates the effect of filtrate invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs. Numerical simulation approach is used to build the reservoir model based on data acquired from a tight gas reservoir. The model undergoes water injection followed by gas production from different testing points along the wellbore, and the corresponding pressure gradients are plotted to check for pressure matching with that of the formation fluid in the virgin region. The results indicate the significant effects of supercharging, reservoir characteristics, capillary pressure and liquid invasion damage on wireline formation pressure measurements in tight gas reservoirs.

Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves. The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs. This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.

Low permeability and complexities of rock formation in tight gas reservoirs make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional reservoirs in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally consisted by the stacks of isolated lenses of sand bodies that are separated by impermeable layers (e.g. shale). Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs. This study shows the effect of drainage pattern of the lenticular sand bodies on production performance, gas in place (GIP) estimation using P/Z vs Gp method, and ultimate gas recovery in tight gas formations. Numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs. The results highlighted that in tight gas reservoirs, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Drainage of gas from the reservoirs is controlled by the sand lens width, and the size of sand lenses in the direction parallel to the hydraulic fracture wings does not have significant effect on gas recovery. The drainage area of the tight gas reservoirs is limited to the area perpendicular to the hydraulic fractures wings, and therefore P/Z vs Gp method may underestimate the value of GIP calculated for the lenticular/elliptical shape sand lenses.

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they might not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, water blocking, relative permeability reduction around wellbore as a result of filtrate invasion and liquid leak-off into the formation during fracturing operations. Drilling and fracturing fluids invasion mostly occurs through permeable zones or natural fractures and might also lead to serious permeability reduction in the rock matrix that surrounds the wellbore, natural fractures, or hydraulic fracture wings. This study represents evaluation of water blocking damage in tight gas formations, and the influence on core flow efficiency and well productivity. Core scale reservoir simulations were carried out based on a typical Western Australia tight gas reservoir in order to numerically model liquid invasion during overbalanced, balanced and underbalanced drilling, and the effect on gas production in clean-up period. The simulation results describe how water blocking reduces near wellbore permeability and affects well productivity and gas recovery from tight gas reservoirs.

Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation. Tight reservoirs need advanced drilling and completion techniques to efficiently connect wellbore to the formation open natural fractures and produce gas at commercial rates. Stress regimes have significant influence on tight gas reservoirs production performance. The stress regimes cause wellbore instability issues while drilling, which can result in large wellbore breakouts. The stress regimes can also control the well long-term production performance, since they affect permeability anisotropy. The preferred horizontal flow direction is expected to be parallel to the maximum in situ horizontal stress. The production and welltest data in non-fractured as well as hydraulically fractured wells in tight reservoirs have indicated the presence of a long-term linear flow regime due to the well and reservoir geometry and also as a result of the permeability anisotropy. The stress anisotropy leads to different permeabilities in different directions, and the natural fractures that are aligned with maximum horizontal stress; they might have larger aperture and greater permeability. Due to the more severe stress anisotropy in tight formations, permeability in maximum stress direction might significantly be larger than permeability in the direction of minimum stress. This study represents evaluation of parameters that might control well productivity and long-term well production performance in tight gas reservoirs. Geomechanical modeling is performed in order to understand the effect of stress anisotropy on aperture evolution of natural fractures in different directions. Furthermore, single well reservoir simulation study is performed in order to generate pressure build-up data for a typical tight gas reservoir, in order to evaluate effect of reservoir geometry and permeability anisotropy on late time linear flow regime, and also assess the well production performance for different well and reservoir conditions.

Welltest interpretation requires diagnosis of reservoir flow regimes in order to determine the basic reservoir characteristics such as average reservoir permeability and skin factor. Due to wellbore storage effect, wellbore phenomena and complexity of reservoir response from heterogeneous reservoir layers, detection of the reservoir flow regimes using standard welltest diagnostic plots might be challenging and have some uncertainties. In pressure transient testing, there are instances where the flow regimes might not clearly be revealed on diagnostic plots of pressure build-up and its derivative, such as incomplete pressure build-up tests, low permeability reservoirs and multi-phase producing wells. In such cases, the Semi-Log plot of first and second derivative of transient pressure versus time can be used to reduce the uncertainties associated with welltest analysis. This paper describes a new method for well test interpretation using second derivative of transient pressure. Two field examples are shown in which a reliable radial flow regime on pressure build-up data could not be detected using standard plots. The second derivative approach was used to predict radial flow regime trend and estimate the reservoir permeability and skin factor, which the results were in good agreement with production data in these wells.

Abstract Fractures identification is essential during exploration, drilling and well completion of naturally fractured reservoirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formation properties and fluid flow behaviour such as logging and testing. Pressure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended technique for fracture evaluation, but its use is still not well understood. Analysis of pressure transient data provides dynamic reservoir properties such as average permeability, fracture storativity and fracture conductivity. An infusion of geological knowledge helps reducing uncertainty associated with any well-test interpretation. The static properties of naturally fractured reservoirs such as fracture aperture, fracture spacing and fracture porosity can be obtained from processing of Image Log data. Simulation of naturally fractured reservoirs needs defining fracture permeability, shape factor and fracture porosity in the fracture model. However, in most simulation studies, due to high uncertainties in estimating fracture permeability and shape factor values, these parameters are initially assumed in the model and they are usually tuned during history matching which can be time consuming and also affect other history match parameters. Reservoir simulation results and predictions might be inaccurate if the values of fracture properties in the model are not reliable. This paper shows using image log data associated with welltest analysis in order to determine dynamic fracture parameters such as fracture permeability and shape factor for reservoir simulation. In this study, sensitivity analysis has also been performed on fracture permeability, fracture porosity and shape factor in a real simulation model to show importance of accurate determination of fracture parameters. Introduction Naturally fractured reservoirs differ from homogeneous reservoirs from many points of view: geological, petrophysical, production and economics. We may think of fractured reservoirs as initially homogeneous systems whose physical properties have been deformed or altered during their deposition. As a consequence, it is not always easy to match the behavior of these systems, specifically to forecast their production during simulation.

The identification of fractures is essential during exploration, drilling and well completion of naturally fractured reservoirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formation properties and fluid flow behaviour such as logging and testing. Pressure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended technique for fracture evaluation, but its use is still not well understood. Analysis of pressure transient data provides dynamic reservoir properties such as average permeability, fracture storativity and fracture conductivity. An infusion of geological knowledge helps reducing uncertainty associated with any well-test interpretation. The static properties of naturally fractured reservoirs such as fracture distribution, fracture aperture, matrix block size and fracture porosity can be obtained from processing of Image Log data. Simulation of naturally fractured reservoirs needs defining fracture permeability, shape factor and fracture porosity in the fracture model. However, in most simulation studies, due to high uncertainties in estimating fracture permeability and shape factor values, these parameters are initially assumed in the model and they are usually tuned during history matching which can be time consuming and also affect other history match parameters. Reservoir simulation results and predictions might be inaccurate if the values of fracture properties in the model are not reliable. This paper shows using image log data associated with welltest analysis in order to determine dynamic fracture parameters such as fracture permeability and shape factor for reservoir simulation. In this study, sensitivity analysis has also been performed on fracture permeability, fracture porosity and matrix block size in real simulation models in order to show importance of accurate determination of fracture parameters.

Abstract Interpretation of temperature logs has been done successfully in wells to identify water or gas entries location, detect casing leaks, and evaluate cement placement. This paper shows how knowledge of the Joule-Thomson cooling effect and frictional heating effect can be applied for well test interpretation. Many analysts rely on pressure derivative curve to diagnose wellbore storage period and radial flow regime on pressure transient data. However, there are field examples that flow regimes can't be accurately determined. During transient tests, both pressure and temperature are changed depending on downhole flow rate. In gas producing wells, Joule-Thomson cooling and frictional heating effects are the main dynamic factors causing flowing bottomhole temperature to differ from the static formation temperature at that depth. When a gas well is shut in, JT cooling effect is vanished and this causes a sharp increase in sandface temperature. As effect of WBS ends, wellbore temperature gradually cools down due to heat conduction with near wellbore region. This paper demonstrates a new technique for determining end of wellbore storage in pressure build-up tests for gas producing wells using temperature transient data. Application of this robust technique was demonstrated using three gas wells in which both temperature and pressure transient data were analyzed for more accurate welltest interpretation. Introduction In pressure transient tests [1], the early portion of the well test data is usually affected by the wellbore storage effect and might be influenced by skin[2] and reservoir permeability. The wellbore storage effect delays the formation pressure response and distorts the early portion of pressure transient data. Diagnosing of the radial-flow regime is crucial to quantitative interpretation since it provides values for permeability and skin. Unit slope and the plateau on the pressure derivative curve as well as Horner plot are usually used to identify pure wellbore storage and radial flow regime as shown in Fig.1. The interpreter's first task always is to identify the unit slope line and derivative plateau to identify flow regimes [3].

Tight gas reservoirs incur problems and significant damage caused by low permeability during drilling, completion, stimulation and production. They require advanced improvement techniques to achieve flow gas at optimum rates. Water blocking damage (phase Trapping/retention of fluids) is a form of mechanical formation damage mechanism, which is caused by filtrate invasion in drilling operations mostly in fracturing. Water blocking has a noticeable impact on formation damage in gas reservoirs which tends to decrease relative permeability near the wellbore. Proper evaluation of damage and the factors which influence its severity is essential to optimize well productivity. Reliable data regarding interfacial tension between gas and water is required in order to minimize mechanical formation damage potential and to optimize gas production. This study was based on the laboratory experiments of interfacial tension by rising drop method between gas-brine, gas-condensate and gas-brine. The results showed gas condensate has low interfacial tension value 6 – 11 dynes/cm when compared to gas-brine and gas- diesel which were 44 – 58 dynes/cm and 14 – 19 dynes/cm respectively. In this way, the capillary pressure of brine-gas system was estimated as 0.488 psi, therefore diesel-gas system was noticed about 0.164 psi and 0.098 psi for condensate-gas system. A forecast model was used by using IFT values to predict the phase trapping which shows less severe phase trapping damage in case of condensate than diesel and brine. A reservoir simulation study was also carried out in order to better understand the effect of hysteresis on well productivity and flow efficiency affected due to water blocking damage in tight gas reservoirs.

Piezoelectrics are increasingly being used in a large number of research explorations and engineering applications. In industry, piezoelectrics are widely being accepted as sensors, giving engineers more leverage to add new features to their products. In recent years, for example, distributed piezoelectric sensors and actuators are widely used in active vibration control of structures or precision mechatronic and structronic systems. In this paper, a piezoelectric quad-morph based multiple degrees of freedom (DOF) end-effector is designed and its multi-DOF precision placement operation is analyzed. This new multi-DOF cantilever beam design consists of multiple piezoelectric rectangular rods glued together, which provides a way to accurately position the end in space. Detailed analysis of this advanced composite structure is carried out by the finite element method incorporating the piezoelectric actuations.

Piezoelectric materials are increasingly being applied to various fieldS of research and engineering applications. In recent years for example, much work has been concentrated on active vibration control of structures by incorporating piezoelectric as both sensorS and actuators. In the industry, piezoelectrics are widely being accepted as effective sensors, giving engineers more leverage to add new features to their products. In this paper, piezoelectric composite structure is studied for precision placement of a multiple degrees off freedom (DOF) end–effector per the converse piezoelectric effect. This new design of the multi–DOF cantilever beam, by attaching multiple piezoelectric rectangular rods together, will provide a way to accurately position the end of this beam structure. The computation of this advanced composite structure is done by the finite element method incorporating the piezoelectric effects.

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.

With the reduction of conventional reserves, the demand and exploration of unconventional sources becomes increasingly important in the energy supply system. Low permeability, low porosity, and the complexities of rock formation in unconventional gas reservoirs make it difficult to extract commercially viable gas resources. Hydraulic fracture is the most common technique used for commercial production of hydrocarbon resources from unconventional tight-gas reservoirs. Due to the existence of an extremely long transient-flow period in tight-gas reservoirs, the interpretation of welltest data based on conventional welltest analysis is quite challenging, and could potentially lead to misleading results. This peer-reviewed paper presents a new approach based on a log-log reciprocal rate derivative plot. Emphases are given on the identification of factors affecting the welltest response in multiple hydraulic-fractured wells in unconventional gas reservoirs based on numerical simulation. The objective is to investigate the sensitivity of various reservoir and hydraulic-fracture parameters, such as multiple hydraulic-fracture size, fracture number and fracture orientation on welltest response, and the effect of the pressure derivative curve on the slopes of welltest diagnostic plots, as well as on well productivity performance. The results can be used to understand the welltest response for different hydraulic-fracturing scenarios for the efficiency and characteristics of hydraulic fractures.

Wireline formation testing and measurement of true formation pressure can provide essential knowledge about the reservoir dynamic characteristics. In tight formations, a reliable determination of pressure and mobility gradients is challenging because of the tight nature of formation rock. Due to the very low reservoir permeability, the mud cake across wellbore is often ineffective in preventing filtrate invasion, thus causing the measured pressure to be higher than actual formation pressure as a result of supercharging effect. Wireline formation testing measurements are also influenced by the effects of filtrate invasion and capillary pressure, as the measured pressure is pressure of drilling fluid filtrate, the continuous phase present in the invaded region around wellbore. As a result, the measured pressure might be different to true formation pressure. This effect is more noticeable in tight gas reservoirs due to capillary pressure effect. This paper looks into estimation of true formation pressure and evaluates the effect of filtrate invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs. Numerical simulation approach is used to build the reservoir model based on data acquired from a tight gas reservoir. The model undergoes water injection followed by gas production from different testing points along the wellbore, and the corresponding pressure gradients are plotted to check for pressure matching with that of the formation fluid in the virgin region. The results indicate the significant effects of supercharging, reservoir characteristics, capillary pressure and liquid invasion damage on wireline formation pressure measurements in tight gas reservoirs.

Low matrix permeability and significant damage mechanisms are the main signatures of tight-gas reservoirs. During the drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around the wellbore, and eventually reduces permeability at the near wellbore zone. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage, making water blocking and phase trapping damage two of the main concerns with using a water-based drilling fluid in tight-gas reservoirs.Therefore, the use of an oil-based mud may be preferred in the drilling or fracturing of a tight formation. Invasion of an oil filtrate into tight formations, however, may result in the introduction of an immiscible liquid-hydrocarbon drilling or completion fluid around the wellbore, causing the entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using a water-based drilling fluid in comparison with the use of an oil-based drilling fluid in water-sensitive, tight-gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and the results of laboratory experiments of core flooding tests in a West Australian tight-gas reservoir are shown, where the effect of water injection and oil injection on the damage of core permeability are studied. The results highlight the benefits of using oil-based fluids in drilling and fracturing of tight-gas reservoirs in terms of reducing skin factor and improving well productivity.

Exponential decline curve analysis is widely used to estimate recoverable reserves due to its simplicity. In most cases, however, an exponential model cannot provide a satisfactory match of overall production history. The generalised form of a hyperbolic decline model is more powerful in matching production history than the other decline models, but it is difficult to apply in practical production data analysis since it requires predicting two unknowns as decline constants. Although a hyperbolic model may provide a good fit to early-time production decline data; it may overestimate the late-time production, especially for hydraulic fractured wells in a tight-gas reservoir. In fact, the exponential decline model might be more reliable for forecasting the late-time production. This paper presents a practical approach to production decline analysis for non-fractured and fractured wells in a tight-gas reservoir using numerical simulation. Some production rate functions and type curves are introduced to obtain the best matching values of hyperbolic, exponential and harmonic production decline constants. The simulated production rate decline data for various well and reservoir parameters are used to indicate the optimum time duration of use of each decline model and to show the time when the production decline starts following the exponential model. The proposed approach is applied in production data analysis and forecasting for a tight-gas field in WA. The results showed good agreement with the production forecast obtained from a reservoir simulation.

Objective: To determine the pattern of muscle involvement in patients with ulnar neuropathy at the elbow. Materials and Methods: This study evaluated all patients referred for upper limb electrodiagnostic study (EDX) during 2007-2011 and included. patients with clinical signs and symptoms of ulnar neuropathy at the elbow. All patients had nerve conduction studies (NCS) for ulnar neuropathy. Needle electromyography (EMG) of four ulnar innervated muscles, flexor carpi ulnaris (FCU), flexor digitrom profoundus (FDP), first dorsal interosseous (FDI) and abductor digiti minimi (ADM)) was evaluated. Results: During the study period 34 (23 males and 11 females) patients were diagnosed with ulnar neuropathy at the elbow and three of them had bilateral involvement. Muscle involvement by EMG was as follows: FDI: 91.9%, ADM: 91.3%, FCU: 64.9% and FDP: 56.8%. Conclusion: In this study, EMG abnormalities of nerve damage were presented more commonly in the FCU muscle than in the FDP in patients with ulnar nerve lesion at the elbow.

Welltest interpretation requires the diagnosis of reservoir flow regimes to determine basic reservoir characteristics. In hydraulically fractured tight gas reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, heterogeneity, and complexity of reservoir. Thus, the use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, the second derivative of transient pressure may help eliminate a number of uncertainties associated with welltest analysis and provide a better estimate of the reservoir dynamic parameters. This paper describes a new approach regarding welltest interpretation for hydraulically fractured tight gas reservoirs—using the second derivative of transient pressure. Reservoir simulations are run for several cases of non-fractured and hydraulically fractured wells to generate different type curves of pressure second derivative, and for use in welltest analysis. A field example from a Western Australian hydraulically fractured tight gas welltest analysis is shown, in which the radial flow regime could not be identified using standard pressure build-up diagnostic plots; therefore, it was not possible to have a reliable estimate of reservoir permeability. The proposed second derivative of pressure approach was used to predict the radial flow regime trend based on the generated type curves by reservoir simulation, to estimate the reservoir permeability and skin factor. Using this analysis approach, the permeability derived from the welltest was in good agreement with the average core permeability in the well, thus confirming the methodology’s reliability.