Gas Condensate Wells Research Articles

Experimental Studies of Efficient Wells Completion in Depleted Gas Condensate Fields by Using Foams

Abstract The reasons for decreasing the well operating parameters of depleted gas condensate fields have been analysed. A new approach has been proposed, which involves restoring the wells productivity by creating foam by means of a device developed for removing liquid from the well bottom. The expediency of using foam has been experimentally investigated for gas condensate wells to be completed and their productivity to be recovered. Techniques for removing liquid contaminants from wells have been developed, which involve injecting non-explosive gas mixtures and foams of various volumes into wells. Computational fluid dynamics modelling of the operation of the device for the wells completion with foam was carried out. The influence of the mass flow rate of an aqueous solution at the inlet to the device on the distribution of volume fraction of the gas and liquid phases, and the quality of the foam has been investigated. The understanding of the regularities of foam destruction processes by hydrocarbon condensate was obtained, and a device design was developed for the complete foam destruction.

Development of foam-breaking measures after removing liquid contamination from wells and flowlines by using surface-active substances

The purpose is to consider the complications that arise during the operation of gas condensate wells, in particular, the accumulation of liquid contamination. Development of new approaches to improve the efficiency of the separation equipment performance of gas gathering and treatment systems when a multiphase flow enters. Development of a foam breaking method in a gas-liquid flow after removal of liquid contaminants from wells and flowlines using surfactants. An analysis was made of the complications that may arise when removing liquid contaminants from wells and flowlines using surfactants. Measures have been developed that will make it possible to timely prevent the ingress of foam into the separation equipment of gas gathering and treatment systems. Using computational fluid dynamics (CFD) modelling, an effective foam-breaking device was developed by supplying stable hydrocarbon condensate. A method to minimize the negative impact of foam on the operation of separation equipment after fluid removal from wells and gas condensate field flowlines using a surfactant solution was elaborated. A method for its breaking was proposed to prevent the flow of foam into the gas processing unit. This method foresees the application of the technological scheme layout for supplying a stable hydrocarbon condensate to a gas-liquid flow entering the separators of the first of separation, both the main line and the measuring line. CFD modelling was used to study the process of foam breaking by feeding hydrocarbon condensate into it. The influence of the hydrocarbon condensate supplying method on gas-dynamic processes (distribution of pressure, velocity, volumetric particles of phases), and the efficiency of foam breaking was estimated. It was established that the supply of hydrocarbon condensate from one branch pipe to the pipeline through which the foam moved did not ensure its complete breaking. To increase the efficiency of foam breaking, a device with designed four nozzles for supplying hydrocarbon condensate was developed. CFD modelling made it possible to substantiate that in this case, a pressure reduction zone appeared at the place of condensate supply. Because of a sharp change in pressure, a strong improvement in the effect of foam breaking occurred. The understanding of the regularities of foam breaking processes by hydrocarbon condensate was obtained, and the design of a device for the complete foam breaking was developed. The obtained results of laboratory studies have shown that a sharp decrease in the stability of the foam occurs under the condition of an increase in the volume of stable hydrocarbon condensate added to the studied model of mineralized formation water. Based on the results of CFD modeling, a device for breaking foam by stable hydrocarbon condensate has been worked out, the effectiveness of which will be confirmed experimentally and in field conditions. The results of the performed laboratory studies and CFD modelling allow a more reasonable approach to using various available methods and measures to prevent the ingress of foam with a gas-liquid flow into the separation equipment of gas gathering and treatment systems. This approach makes it possible to develop new effective ways and measures to prevent this complication. Based on CFD modelling, it was found that when a stable hydrocarbon condensate is supplied into a gas-liquid flow, foam breaks. A method for breaking foam in a gas-liquid flow has been developed, which is original and can be introduced in practice.

Experiment and Application of Wax Deposition in Dabei Deep Condensate Gas Wells with High Pressure

The Dabei deep high-pressure condensate gas field occupies the paramount position in the Tarim Oilfield in China, the exploration and developments of which have been progressing. Since the initial development, the wax deposition and plugging in the wellbore and gathering pipeline have been the most bothering issues, resulting in the reduction or even shutdown of condensate gas well production. Therefore, the wax appearance temperature of Dabei condensate oil was studied using the capillary viscometer, differential scanning calorimetry (DSC), and polarizing microscope observation. The wax content was tested by using the DSC and crystallization separation test method. Finally, the wax appearance temperatures of degassed condensate oil and equilibrium condensate oil under different pressures were tested. Experimental results show that the wax appearance temperature measured by polarizing microscope observation was higher than that measured by the DSC and capillary viscometer, the lag of which can be recorded as the cloud point. The wax appearance temperature measured by polarizing microscope observation is of high accuracy. Secondly, the DSC method is not sufficient for measuring wax precipitation at low temperatures, showing a lower wax content than the crystallization separation test method. Thus, the wax content of Dabei condensate oil can be better measured by using the crystallization separation test method. Additionally, the wax precipitation law of equilibrium condensate oil is opposite to that of degassed condensate oil. The wax appearance temperature of equilibrium condensate oil increases as the pressure decreases. The results of wax appearance temperature of equilibrium condensate oil provide a useful and quick index to judge the potential risk of wax precipitation in the Tarim Oilfield, which can provide an efficient strategy for the development of waxy condensate gas reservoirs and the optimization of wax prevention and treatment technology.

Gas Condensate Wells: Challenges of Sampling, Testing and Production Optimization

The main problem of fluid sampling during well testing of reservoirs with near-critical fluids (gas condensate and volatile oil) is due to the fact that even a small pressure drawdown usually leads to the formation of a two-phase mixture in the bottom hole area, and it is almost impossible to take representative samples with downhole samplers or a formation tester. Sampling via test-separator and the current non-separation methods are also imperfect. An alternative method—MIKS (Multiphase IsoKinetic Sampling)—of gas condensate well testing was proposed, which is based on emulsifying a multiphase flow to particles of about 1–10 μm. Thereby MIKS would eliminate the problem of particle slippage in a homogeneous flow and enables high-quality sampling directly from the flowmeter line. The initial formation fluid is characterized by the maximum value of the condensate-gas ratio (CGR). Therefore, first, the well effluent would be adjusted to the mode with the maximum CGR using a choke manifold and a multiphase flow meter. Then the flow mixture is transferred to a by-pass line with an emulsifier to achieve an isokinetic flow. Thereafter, pressure samples can be taken into pressurized sampling bottles, in which thermodynamic conditions are preset according to the flow line. The efficiency of sampling and recombining procedures allows for conducting a study of reservoir samples in the field laboratory directly on the rig and obtaining a complete PVT report even before the completion of drilling and abandonment of the well. An additional economic effect is achieved by reducing the costs of transporting and samples storage. Well test equipment setup becomes much more compact and less weight; the costs of drilling time are reduced, which is viably important for well testing on the Arctic conditions. Another major problem in the development of gas condensate reservoirs is avoiding the condensate banking around producing wells. Optimization of condensate production can be achieved by maintaining the well operation mode at maximum CGR level by means of multiphase flowmeters. The formed condensate bank can be destroyed by a combination of methods—hydraulic fracturing, followed by cycling process—purging the formation with dried gas and/or injection of methanol into the formation. Methanol can be obtained from synthesis gas as a by-product in the utilization of associated gas also at the field. The specified set of measures will allow to revive the GC wells that are losing productivity, as well as to extend the period of high productivity of new wells.

A State of the Art Review on the Wellbore Blockage of Condensate Gas Wells: Towards Understanding the Blockage Type, Mechanism, and Treatment

Abstract With the development of high-pressure and high-temperature condensate gas wells, the wellbore blockage problems have become increasingly serious. Hence, selecting appropriate treatment technology plays a crucial role in solving the wellbore blockage problems. This study presents a comprehensive literature review on understanding the blockage type, mechanism, and treatment of the high-temperature and high-pressure condensate gas wells. The causes, endangerments, mechanisms, influences, and preventive technologies of the 4 wellbore blockage types are presented. The significant aspects of the treatment technology, such as the principle, type, advantage and disadvantage, adaptability, limitation, and future research direction of the treatment technologies, are thoroughly discussed. The breakthrough solid autogenetic heat treatment technology has been selected to remove hydrate blockage. The present review highlights the current state in the industry, future position, and strategies for the researchers to follow. Finally, the advantages and disadvantages and future research directions of specific treatment technology are presented on the removing effect, cost, and environmental aspects.

DETERMINATION OF THE MINIMUM GAS FLOW RATE REQUIRED FOR COMPLETE REMOVAL OF CONDENSATE FROM THE WELL IN GAS-CONDENSATE WELLS

The article provides a brief analysis of the determination of the minimum gas flow rate required for complete removal of condensate from the wellbore in gas condensate wells. In gas wells, water collects in the wellbore as a result of condensation of produced water and steamed water entering the wellbore together with the well product. In gas condensate wells, gas condensate from the formation is added to it. Thus, part of the filters of gas and gas condensate wells is filled with liquid, which ultimately reduces the flow rate of these wells. At the beginning of the development and operation of gas and gas condensate fields, the amount of liquid (water) and condensate in the gas is low, and due to high formation pressure in the first period of this field, raised to the surface. Over time, the velocity of the well product in the gas condensate wells gradually decreases, and as the amount of water and condensate entering the reservoir increases, the fluid accumulates in the well as the reservoir cannot be fully lifted by its own energy. This creates a counter-pressure on the bottom of the well and affects the formation, which closes with a liquid column in the filter section of the well, which significantly reduces the flow rate of the well, and in some cases leads to a complete shutdown of the well. Various methods have been developed and are still being used to prevent this and to ensure the efficient operation of gas and gas condensate. Keywords: layer waters, condensation, gas condensate, filter, layer pressure, well bottom.

COMPLICATIONS IN THE OPERATION OF OFFSHORE CONDENSATE WELLS AND THE CHOICE OF METHODS TO COMBAT THEM

The article provides a brief analysis of the complications in the operation of offshore condensate wells and the choice of methods to combat them. The issue of improving and accelerating the development and operation of oil, gas and gas condensate fields has always been relevant and is still relevant today. Development and operation of hydrocarbon deposits is accompanied by the following complications: Complications in the operation of oil wells; irrigation of oil well products; intensification of sand manifestations in deposits; Complications in the operation of clean gas fields; Complications in the operation of gas condensate wells, etc. In order to eliminate all these complexities in the development and operation of hydrocarbon fields, the development of measures in the dissertation, their implementation is very important, as they increase the coefficients of oil, gas and condensation and reduce the cost of oil, gas and condensate.. Keywords: condensate, complexity, hydrocarbon, sand formation, gas condensate, gas supply.

Mathematical Justification for Optimizing Operating Conditions of Gas and Gas Condensate Producing Wells

The paper investigated the problem of selecting/finding the optimal process conditions for gas condensate wells. The well process conditions imply a set of parameters that characterize its operation. The optimization of process conditions provides for the efficient operation of an oil and gas field while meeting the defined boundary and initial conditions, and allows for the process/production goal to be achieved. This paper proposed using the tree-structured Parzen estimator (TPE), which allows for the results from previous iterations to be considered, in order to identify the most promising region of conditions, thereby increasing the optimization efficiency. The movement of multiphase fluid inside the pipeline system (also in the borehole) must be calculated to solve the process optimization problem. The optimization module was integrated into the hydraulic and unsteady state multiphase flow calculations inside the well and the pipeline. The platform created allows for the process conditions at gas condensate fields to be identified via the use of numerical methods. The proposed optimization algorithm was tested in delivering the task of optimizing the process conditions in 13 producing wells in a part of a real gas condensate field in Western Siberia. The engineering problem of optimizing the production of gas and the gas condensate was solved as a consequence of the calculations performed.

Optimization and Performance Evaluation of Foam Discharge Agent for Deep Aquatic Condensate Gas Well

The block deep condensate gas reservoir in the basin in the southeast of the South China Sea is a bottom water reservoir and is producing in the late effusion, which faces problems such as scaling, condensate oil–water two-phase flow, and low temperature at the subsea wellhead. The mud line for this kind of gas-well has characteristics including high condensate content in low temperature, high downhole temperature, and injection with a foam discharge agent and scale inhibitor. In this article, the influence of low temperature and scale inhibitor is considered for the first time, and a dynamic liquid-carrying experiment for the optimization and performance evaluation of foam discharge agents was carried out according to these characteristics. The experimental results show that the optimized foam discharge agent, ZHY-01, has good resistance to high temperature and condensate oil, and the optimal concentration of the foam discharge agent is recommended to be 0.25%. Under this concentration, the liquid-carrying capacity of the foam discharge agent decreases slightly by 10.17% at low temperature. The scale inhibitor MA/AA reduced the liquid-carrying capacity by 11.86%, and the scale inhibitor PESA reduced the liquid-carrying capacity by 10.17%. The research results in this article have certain reference significance for the chemical screening and evaluation of the foam drainage gas production process in deep-water condensate gas wells.

Geological Model of the Khabour Reservoir for Studying the Gas Condensate Blockage Effect on Gas Production, Akkas Gas Field, Western Iraq

The Khabour reservoir, Ordovician, Lower Paleozoic, Akkas gas field which is considered one of the main sandstone reservoirs in the west of Iraq. Researchers face difficulties in recognizing sandstone reservoirs since they are virtually always tight and heterogeneous. This paper is associated with the geological modeling of a gas-bearing reservoir that containing condensate appears while production when bottom hole pressure declines below the dew point. By defining the lithology and evaluating the petrophysical parameters of this complicated reservoir, a geological model for the reservoir is being built by using CMG BUILDER software (GEM tool) to create a static model. The petrophysical properties of a reservoir were computed using the notion of hydraulic units, and there are a number of basic steps to building a geological model, beginning with the creation of a single well model and then moving on to the distribution of properties. Depending on the variance in petrophysical parameters, the reservoirs were separated into seven zones. The Ordovician Formation (Khabour Formation) is penetrated by well Akk-1, which is included in the single well geological model to focus on studying the impact of gas condensate on gas production. The prediction of gas condensate wells production will strongly depend on oil banking evaluation and modeling. For this reason, well Akk-1 was chosen to build the model. Upper and lower sandstone units characterized as the most important due to containing of gas. The cost and risk to develop these reservoirs under severe conditions of pressure and temperature highlight the need to be able to confidently predict the recovery of gas and liquid drop-outs from Khabour reservoirs so, it is so necessary to predict the cost of this step in another paper

Numerical Study of the Fluid Flow Around the Vertical, Deviated, and Horizontal Gas Condensate Wells From the Perspective of Fundamental Forces

Abstract The well performance in gas condensate reservoirs (GCRs) is an essential factor addressing the condensate recovery. A vast and growing number of studies, including numerical simulations, have compared the deliverability of vertical, deviated, and horizontal wells in GCRs, because of the high economical values gained from these fields; it is worthy of further investigation from a new point of view. Here, we conduct an investigation into the well performance in different cases (vertical, deviated, and horizontal) in GCRs based on the fundamental forces that exist around the well. The most important fundamental forces affecting the fluid flow are inertial, viscous, capillary, and gravitational forces. The force ratios were expressed as some dimensionless numbers to adequately assess and compare the relative strength of fundamental forces around the well. These dimensionless numbers were calculated using simulation results and data from a real GCR which is in the Middle East for three cases of vertical, deviated, and horizontal wells. As a result, a general graphical representation was provided to indicate the relative importance of fundamental forces in different reservoir’ regions. The results of this study, as a qualitative criterion, can be used in checking or modifying the relative permeability correlations of GCRs.

Повышение технологической эффективности глушения скважин с использованием инновационных технологий

Introduction. The article considers the issue of assessing the technological efficiency of the well killing process, taking into account changes in the reservoir properties of the productive formation when using various compositions of process fluids. Innovative technologies are presented that are used when killing wells in various mining and geological conditions to block the bottomhole formation zone. Materials and methods of research. The study is based on a summary of many years of experience in the field of creation and practical use of process fluids for killing wells and on the results of theoretical, laboratory, bench studies of killing fluids and blocking compositions, performed in specialized scientific laboratories using specialized laboratory equipment according to standard methods for the oil and gas industry. Research results and discussion. The compositions of process fluids are presented, which are easily removed when inducing inflow from the formation, and which allow to provide the required pressure at the bottomhole, as well as to maintain the reservoir properties of the productive formation and prevent its damage. The results of killing wells with the use of various compositions of process fluids with high stability, low filtration, in a wide range of adjustable density and rheological properties, which allow creating the necessary repression on the formation and performing various operations in the well, are considered. The article also provides information on the analytical studies carried out within the framework of the given problem. The results made it possible to draw conclusions regarding the use of various types of fluids for killing oil, gas, gas condensate wells under conditions of abnormally low reservoir pressures and elevated reservoir temperatures. Consideration is given to the liquids with an acidsoluble condensable solid phase, the formation of which in solution is due to the occurrence of physicochemical processes between its components; biopolymer-based liquids containing various fillers and functional additives; viscoelastic compositions reinforced with solid-state lamellar and fibrous particles of organic and mineral origin (for example, bridging additive brand «OM-2C») based on commercially available polymer reagent «Binar»; emulsion-type kill fluids containing surfactants and a hydrocarbon phase. The main rheological and technological parameters, as well as the properties of the proposed process fluids for killing wells, are described. Сonclusions. Based on the study, it was determined that the most promising technology for killing wells under conditions of abnormally low formation pressures is the technology of preliminary blocking of the bottomhole formation zone using special compositions of process fluids with controlled rheological parameters, taking into account the characteristics of the formation, technologically applicable in special climatic conditions with low negative temperatures. It has also been established that ensuring high efficiency of repair work is impossible without performing theoretical calculations and laboratory studies with modeling the process of blocking the bottomhole zone during well killing and subsequent development.

Development of technology for production recovery of gas-condensate wells

Development of technology for production recovery of gas-condensate wells

A Two-Phase Flow Model for Reserves Estimation in Tight-Oil and Gas-Condensate Reservoirs Using Scaling Principles

Summary A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multiphase flow, which exist once the reservoir pressure falls below the bubble/dewpoint. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. In addition, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight-oil wells in the Wolfcamp Formation of west Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudopressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following: First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors (URFs) for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the pressure/volume/temperature (PVT) properties, which shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two-phase and single-phase solutions under boundary-dominated flow (BDF) conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells because they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubblepoint. Finally, the application of the two-phase model provides a better fit when compared with the single-phase solution. The present model requires very little computation time to forecast production because it only uses two fitting parameters. It provides more realistic estimates of URFs and EURs, when compared with single-phase flow solutions, because it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight-oil and gas condensate wells.

The problem of adapting the gas-condensate reservoir model under conditions of a low volume and low reliability of the initial data

The article is dedicated to the problem of adapting the hydrodynamic model of a gas-condensate reservoir with a low volume and low reliability of the field and laboratory data. The purpose of the work is a qualitative reservoir development forecast. All available formation fluid downhole samples were studied. The authors analyzed water samples taken during the reservoir development process. The monthly production reports data and the gas-condensate well testing installation measurements were used in the article. The authors carried out the hydrodynamic model multivariate calculations in order to mathematically repeat historical waterflooding. An approach to the retrospective analysis of the production and laboratory data is shown in order to remove uncertainties in the reservoir and production engineering. The work performed made it possible to determine the most probable content of C5+ components in the reservoir gas, as well as to assess the risk of the future formation water invasion into the reservoir. As a result of this work, it was recommended to exclude two edge wells in order to reduce the gas well waterflooding. In addition, the authors calculated an improved reservoir development variant. They proposed to transfer a part of gas wells to water wells at the stage of declining production. This operation will reduce the reservoir water-flooding rate.

Robust hybrid machine learning algorithms for gas flow rates prediction through wellhead chokes in gas condensate fields

Condensate reservoirs are the most challenging hydrocarbon reservoirs in the world. The behavior of condensate gas reservoirs regarding pressure and temperature variation is unique. Adjusting fluid flow rate through wellhead chokes of condensate gas wells is critical and challenging for reservoir management. Predicting this vital parameter is a big step for the development of condensate gas fields. In this study, a novel machine learning approach is developed to predict gas flow rate (Qg) from six input variables: temperature (T); upstream pressure (Pu); downstream pressure (Pd); gas gravity (γg); choke diameter (D64) and gas–liquid ratio (GLR). Due to the absence of accurate recombination methods for determining Qg, machine learning methods offer a functional alternative approach. Four hybrid machine learning (HML) algorithms are developed by integrating multiple extreme learning machine (MELM) and least squares support vector machine (LSSVM) with two optimization algorithms, the genetic algorithm (GA) and the particle swarm optimizer (PSO). The evaluation conducted on prediction performance and accuracy of the four HML models developed indicates that the MELM-PSO model has the highest Qg prediction accuracy achieving a root mean squared error (RMSE) of 2.8639 Mscf/d and a coefficient of determination (R2) of 0.9778 for a dataset of 1009 data records compiled from gas-condensate fields around Iran. Comparison of the prediction performance of the HML models developed with those of the previous empirical equations and artificial intelligence models reveals that the novel MELM-PSO model presents superior prediction efficiency and higher computational accuracy. Moreover, the Spearman correlation coefficient analysis performed demonstrates that D64 and GLR are the most influential variables in the gas flow rate for the large dataset evaluated in this study.

Prediction of sub-critical two-phase flow through wellhead chokes of gas condensate wells using PSO-LSSVM method

Several empirical correlations for prediction of wellhead gas flow rate have been presented in the literature. In this study, subcritical wellhead choke flow data of gas condensate wells that cover a wide range of flow rates (5.4–113 MMSCF/D) and choke sizes (32–192 64th in) were used to develop an intelligent prediction method. Subcritical two-phase flow wellhead choke data from 193 tests of gas condensate wells in 10 fields have been used. Measured pressure drop across the choke, gas to liquid ratio (GLR) and choke size were the input parameters. PSO-LSSVM method was applied to field-measured test data and optimized model parameters were obtained for prediction of gas flow rate as objective function. In addition, the results were compared with recently published empirical correlations developed for subcritical flow. Accuracy of the proposed model were evaluated with error parameters; AARD (average absolute relative deviation), RSME (relative square mean error), and R-squared. Results show the superiority of the proposed model with high accuracy. Observed data and model prediction matched very well with R 2 of 0.9996 and RMSE of 1.46. In addition, five test data that have not been used in the process of model development (training and testing) were used to assess the generality of the proposed mode. Very good agreement between model prediction and observed gas flow rate data was obtained and can be used for estimation of gas flow rate of subcritical chokes with high confidence.

Problems of hydrate formation in production oil products from gas condensate wells

One of the most important problems in gas production at fields is hydrate formation -a process in which hydrates, settling on the inner walls of technological equipment, reduce their throughput, and therefore it may be necessary to stop the entire technological process for the purpose of unscheduled repairs, which leads to significant economic losses. The article presents the results obtained in the course of research, analytical work, namely: the assessment of the share of hydrocarbon production by region; analyzes of the main methods of combating hydrate formation; development of a methodology for comparing methods of combating hydrate formation among themselves; determining the most acceptable geography for the application of a particular method; forecast of the popularity of the method for 5 years.

Deliverability of Gas condensate "sandstone reservoir"Khabour Fm. Akkas Field,western Iraq

The Khabour Fm. (ordovicain) presents a prospective target for exploration and developiment, as it certains "Gas Condensate" light gravity, low sulfur oil, and sweet gas as proven by Akkas field, in the western desert of Iraq .
 Gas- condensate project is in depth,hot,low permeability reservoir in the upper K1,K3,K5 sandstone members ,it's well known that the deliverability of gas-condensate wells can be improved by the formation of acondensate bank once a bottomhole pressure drope below the dewpoint.
 Improving deliverability can be improved by use the techniques as,Fracturing andchemical treatment.
 The Khabour formation total thickness is 1913m,represntaed by elastic series mainly shaly intercalated with sandstone beds in the lower part and by well developed sandstone beds in the upper part, In Akk-1 which is subdivided into eight members according to sand /shale ratio, the need for accurate estimate for reservoir properties of these member extends to the whole life cycle of a reservoir; detailed
 simulation and planning of future production which including for discovery , appraisal , planning , development and production from Akkas field.

Analyzing the Effects of Gravel Pack Completion on Flowpotential in Gas Condensate Well

Miocene or younger sands are major source of sand production, these type of formations are mostly unconsolidated or only partially consolidated with soft clay or silt, and these formations are structurally weak. These weak formations may not detain sand particle movement, and produce along with the hydrocarbon fluids at high rates. This undesirable sand production can cause many different problems at surface as well as at sub-surface. An effective way of dealing with this problem is the use of gravel pack technique. However, designing gravel pack treatment requires consideration of different influencing parameters. This research aims to study the performance of gravel pack along with the gravel pack height and permeability on the well flow. The approach taken in this study includes the well performance modeling using a commercial simulator. A filed data is collected for gas condensate well that is being produced from Lower Goru Massive Sand Formation. The collected field data is simulated to compare the performance of Gas Condensate well before and after gravel pack completion. With this, the analysis is carried out to determine the effect of gravel pack height 8 permeability on flow parameters (i.e; flow rates of fluids, sand control losses, frictional losses, sand control skin, gravel pack critical velocity). Lastly, an appropriate height and permeable gravel is recommended on the basis of simulation results.