Low-permeability Gas Reservoirs Research Articles

Physical simulation study on production characteristics and mechanism of connate water in gas reservoirs

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs.

Pressure and rate distribution performance of a multiple-fractured well with multi-wing fracture in low-permeability gas reservoirs

Abstract In this work, a new mathematical model of a fractured well considering multiple factors (permeability stress sensitivity, multiple well interference, and multiple fracture interference) is established to simulate wellbore pressure performance and rate distribution in tight gas reservoirs. The new fracture discrete coupling mathematical model is established. The wellbore pressure solution can be obtained by pressure drop superposition and Stehfest numerical inversion. Seven flow stages are observed according to the characteristics of the pressure derivative curve. The influence of several significant parameters, including rate ratio, fracture half-length, well spacing, and stress sensitivity are discussed. Based on the developed model, we demonstrated a field case to verify model accuracy. This work provides new supplementary knowledge to improve pressure data interpretation for multi-well groups in tight gas reservoirs.

A novel approach to determining appropriate additive concentrations for stimulation of gas carbonate reservoirs

This comprehensive study delves into the intricate realm of matrix acidizing treatments within low-permeability gas reservoirs. The research scrutinizes the profound impact of various commercially available additives on acidizing processes, with a keen focus on optimizing their concentrations. By meticulously assessing compatibility, corrosion control, surface tension, and wettability alterations, the study evaluates additives' performance under ambient and reservoir conditions. Notably, four distinct acids—15% hydrochloric acid, 12% hydrochloric acid +3% hydrofluoric acid, 15% acetic acid, and 12% acetic acid +3% hydrofluoric acid—underwent testing with various additives. Through systematic analysis, it's evident that the chosen concentrations of additives yield impressive results: corrosion rates below 0.05 lb/ft2, low surface tension, absence of iron precipitation, and sustained water-wet wettability. The study provides invaluable insights into additive selection, concentrations, and their pivotal role in enhancing acidizing within low-permeability gas reservoirs, ultimately improving overall operational performance and minimizing unfavorable consequences.

Well Testing Analysis Method and Practice for Low Permeability Gas Reservoirs

With the gradual maturity of well testing interpretation theory, some scholars have conducted research on vertical well testing models, horizontal well testing models, and inclined well testing models for fractured and vuggy reservoirs, and plotted typical well testing curves. However, during the drilling process, the wellbore is usually connected to both the fractures and the reservoir matrix, resulting in a dual permeability situation where the fractures and matrix simultaneously supply fluid to the wellbore. Based on this, some scholars have established a horizontal well dual hole dual permeability testing model, a vertical well three hole dual permeability testing model, and a horizontal well three hole dual permeability testing model, making the results of well testing interpretation more reasonable and reliable. For the well testing analysis of inclined wells in fractured and vuggy reservoirs, the existing inclined well models only consider the three hole single permeability situation where the fractures are connected to the wellbore. There is little research on the three hole dual permeability well testing model where the inclined well matrix and fractures supply the wellbore simultaneously. Therefore, based on previous research, this article establishes and solves a well testing model for inclined wells with three pores and dual permeability, using the effective wellbore diameter and the principle of Duhame superposition, taking into account the bottom hole pressure effect, and draws sample curves for the analysis of inclined wells in fractured and vuggy reservoirs. This provides a reference for the analysis of inclined wells in fractured and vuggy reservoirs.

Productivity Formula of Horizontal Well in Low-Permeability Gas Reservoir considering Multiple Factors

For horizontal well in low-permeability gas reservoir, the effects of threshold pressure gradient, stress sensitivity, and gas slippage have significant impacts on the well productivity. At present, there are few productivity formulas for horizontal gas well considering all these factors. In this paper, based on the flow analysis of horizontal well in low-permeability gas reservoir, the whole flow field was divided into two parts, namely, far wellbore region and near wellbore region, among which the far wellbore region is composed of plane linear flow region and plane radial flow region and the near wellbore region is composed of vertical plane radial flow region and spherical plane central flow region. Then, a new productivity formula is established based on the steady-state seepage theory and the equivalent seepage resistance method, with the consideration of threshold pressure gradient, stress sensitivity, and gas slippage effect. The accuracy of the formula in this paper is verified through comparing with other classical models, and the influence of various factors on the well productivity is analyzed. The analysis results show that stress sensitivity has the most significant effect on horizontal gas well production, followed by threshold pressure gradient, and the gas slippage has the least effect. With the consideration of all influencing factors, the higher the formation pressure and reservoir thickness, the higher the productivity, and the increase of productivity increases with the increase of flow pressure difference. The increasing trend of gas productivity index per meter with the increase of reservoir permeability is first fast and then slow. When the reservoir permeability is greater than 1.2 mD, the increment of gas productivity index per meter (MGPI) decreases. When the length of horizontal well is greater than 1400 m, the increment of gas productivity index per meter decreases with the increase of gas reservoir thickness. Therefore, it is recommended to control the horizontal well length within 1400 m in low-permeability gas reservoir. In addition, the absolute open flow charts corresponding to reservoir thickness and horizontal well length under different reservoir permeability conditions were also given, which can provide theoretical guidance for the selection of horizontal well length during the development of low-permeability gas reservoirs.

Modeling Transient Flow Behavior of Off-Center Fractured Well with Multiple Fractures in Radial Composite Gas Reservoirs

Summary Vertical hydraulic fracturing is widely used to develop low-permeability gas reservoirs. Uneven distribution of formation permeability and stress leads to multiple-wing hydraulic fractures with different lengths, which results in the wellbore not being the center of the circular stimulated reservoir volume (SRV) region. Therefore, to simulate the wellbore pressure of this phenomenon, a semianalytical model of the off-center multiwing fractured well in radial composite gas reservoirs is presented and the corresponding solution method is shown. The model is verified with the numerical solution, and eight flow regimes can be distinguished under the ideal case, which includes bilinear flow, fracture interference, linear flow, radial flow of inner region, transition flow of inner region, and radial flow of inner region. Compared with the previous model in which the well is at the center of radial composite gas reservoirs, in this paper we present an obvious “step” after the inner region radial flow regime, which is related to the off-center distance and radius of the inner region. In addition, the effects of some important parameters (such as off-center distance, permeability mobility, inner region radius, and fracture distribution) on typical curves are discussed. Finally, field well testing data are used to verify the accuracy of the model.

Research of influencing factors on permeability for carbonate rocks based on LBM simulation: A case study of low-permeability gas reservoir of Sinian Dengying Formation in Sichuan Basin

Instruction: Due to the declining production rate of conventional natural gas reservoir and the rising demand for natural gas resources, conventional natural gas resources cannot satisfy the needs of economic development. Unconventional gas resource is considered to be the most promising energy supplement, therefore it is an inevitable trend to explore and develop unconventional oil and gas resources such as low permeability reservoirs. At present, the carbonate gas reservoirs in the high permeability area of Sichuan Basin have been almost fully developed, while the remaining gas reservoirs in the low permeability area are not well developed. However, the key factors for effectively enhancing gas recovery rate in different types of low permeability reservoirs are not the same. Even gas reservoirs with the same macroscopic geological characteristics will show different development characteristics through the production processes.Method: In order to analyze the factors affecting the effective production rate of low-permeability gas reservoirs, it is necessary to conduct research from the microscopic perspective, to reveal the effective production conditions of natural gas in low-permeability reservoirs. In this study, low-permeability carbonate samples of Sinian Dengying Formation from Sichuan Basin were taken. Micro-CT scanning technology was used to obtain core images for the carbonate rocks, and the digital carbonate core models at microscopic scale were reconstructed. Based on the reconstructed carbonate digital core models, LBM method was applied to obtain the absolute permeability of the core models.Results: The results imply that the porosity, pore area fraction, throat area fraction, mean throat length, shape factor, coordination number and tortuosity are the factors affecting the absolute permeability of carbonate rocks.Discussion: Subsequently, the relationship between different pore structure parameters and absolute permeability was obtained by multi-parameter fitting method, which provided a new research method for directly predicting the absolute permeability of carbonate rocks by using pore structure parameters.

Research and Application of Shale Gas Reservoir-Wellbore Integrated Model Coupling Method

As a representative of emerging unconventional energy, shale gas has the characteristics of large reserves, long production cycle, and environmental protection. However, due to the complex geological characteristics of shale gas reservoirs, the economic development of shale gas reservoirs is difficult. In this paper, on the basis of a full investigation of relevant literature, according to the permeability mechanism of shale gas reservoirs, the productivity of horizontal wells in low-permeability gas reservoirs is studied, and an integrated dynamic simulation model of gas reservoir wellbore is established. And the historical fitting and dynamic forecasting are carried out, and the results are in good agreement with the actual situation.

Study of the Seepage Mechanism in Thick Heterogeneous Gas Reservoirs

The seepage mechanism plays a crucial role in low-permeability gas reservoirs. Compared with conventional gas reservoirs, low-permeability sandstone gas reservoirs are characterized by low porosity, low permeability, strong heterogeneity, and high water saturation. Moreover, their percolation mechanisms are more complex. The present work describes a series of experiments conducted considering low-permeability sandstone cores under pressure-depletion conditions (from the Xihu Depression in the East China Sea Basin). It is shown that the threshold pressure gradient of a low-permeability gas reservoir in thick layers is positively correlated with water saturation and negatively correlated with permeability and porosity. The reservoir stress sensitivity is related to permeability and rock composition. Stress sensitivity is generally low when permeability is high or in the early stage of gas reservoir development. It is also shown that in sand conglomerates, especially the more sparsely filled parts, the interstitial materials among the conglomerates can be rapidly dislodged from the skeleton particles under stress. This material can therefore disperse, migrate, and block the pore throat producing serious, stress-sensitive damage.

A Semi-Analytical Model of an Off-Center Multi-Wing Fractured Well in a Low-Permeability Gas Reservoir

Summary Since there are several hydraulic fractures around a wellbore after a large-scale hydraulic fracturing and the well is not in the center of the reservoir, no corresponding semianalytical model for wellbore pressure analysis has been proposed. To bridge this gap, this paper aims to present a semianalytical model of the off-center multiwing fractured well. With consideration of permeability stress sensitivity, the reservoir model and hydraulic fracture model are established, respectively. The coupling approach of the reservoir model and hydraulic fracture model is used to obtain the wellbore pressure solution. Meanwhile, the off-center multiwing fractured well is verified with a numerical solution. The seven flow regimes can be distinguished according to the characteristics of the pressure derivative curve. Furthermore, the effect of different fracture distributions on wellbore pressure and the derivative curve is discussed and analyzed. Assuming that the fracture wing number is equal to the average length of all fracture wings, the wellbore pressure is lowest before the radial flow regime when the fracture wing has a uniform distribution around the angle and all fracture wings are equal in length. Besides, the influence of other important parameters (fracture wing number, off-center distance, etc.) is discussed. According to the analysis, we conclude that fracture wing number has a significant influence on the pressure and derivative curves before the radial flow regime. The off-center distance has no influence on the pressure and derivative curve before the radial flow regime, but it has an obvious influence on arc boundary reaction time. Finally, the advantages of the semianalytical solution are fast calculation speed and high calculation accuracy (especially in the early flow regime).

A Novel Strategy Dealing with Producing Period in Low Pressure Gas Wells

Low-pressure gas wells are of increasing interest to the petroleum industry as economic and environmental importance of natural gas continues to grow. To maximize the production of low permeability gas reservoir, a novel production strategy to determine reasonable producing periods, including the pressure draw down process and the pressure build up process, in low pressure gas wells has been investigated. Additionally, the variation of down-hole pressure and gas flow in both processes were considered to formulate the optimization model to find reasonable switching times for low-pressure gas wells in this research. In order to enhance the adaptability of the production strategy proposed in this research, parameters of erosion flow rate, critical flow rate of liquid loading and reasonable differential producing pressure of the reservoirs were considered in the proposed mathematical model which aims at maximizing gas production of low-pressure gas wells. Based on the application of the mathematical model dealing with reasonable production strategy of low-pressure gas wells, the pressure of gas well varies smoothly in both shut-in process and gas production process when the novel production strategy was applied. And nature gas production of the gas well increases dramatically compared with that before.

Productivity performance of open hole horizontal gas well for low permeability gas reservoirs

This study aimed to develop a novel productivity model for an open-hole horizontal well in a low permeability gas reservoir (LPGR). First, the permeability and pressure gradient were revised by the slippage factor, stress-sensitivity coefficient, and startup pressure gradient (SPG). The mirror reflection method was used to solve the influence of top and bottom boundaries on the seepage field, and we can obtain the internal seepage resistance of the well. Second, the Joukowski transformation method can solve the influence of horizontal boundary on the seepage field so that external seepage resistance can be obtained. Finally, by taking the high-velocity non-Darcy effect (NDE) into account, a novel model, which is suitable for an open-hole horizontal well (OHHW) in low permeability gas reservoirs with a high stress-sensitivity coefficient, was developed. The model was verified using data from wells G3 and G4, and the prediction relative errors of the absolute open flow (AOF) of these two wells were only −0.14% and 0.37%, respectively. Then, by comparing with other different models, the results demonstrate that the model constructed in this work has a clear superiority in productivity analysis; it has some guiding significance for the development of open-hole horizontal gas wells in low permeability gas reservoirs.

A novel mode for “three zones” collaborative reconstruction of underground gas storage and its application to large, low-permeability lithologic gas reservoirs

The difficult of reconstruction area selection, the unclear closed boundary and the low injection-production efficiency are the main problems restricting the gas storage reconstruction in large-scale low-permeability lithologic gas reservoir. In view of this, this paper proposes a new ‘three zones' cooperative building model which can provide a comprehensive selecting standard, delimit a stable closed boundary and optimize an efficient operation mode for the successful reconstruction of gas storage in this type of gas reservoir. Its application will create a precedent for the gas storage reconstruction in low-permeability gas reservoir and bring huge economic benefits. First, the multi-parameter comprehensive index evaluation rule of the reservoir under the constraint of “five facies” is established, and the overflow mode and volume of gas in the core area are calculated to define the reasonable range of the ‘three zones'. Subsequently, a mathematical model of fluid exchange between different zones under the new model is established to simulate and predict the dynamic indexes and fluid migration law in different zones. Finally, the operation safety of the gas storage is evaluated, and the applicability and advantage of the new model is confirmed.

Production Performance of Multiple-Fractured Horizontal Well Based on Potential Theory

Abstract These days, hydraulic fracturing is widely applied in the gas reservoir development with low permeability, which can improve the production of the well and enhance the recovery. This paper discussed the productivity characteristics of multiple-fractured horizontal wells (MFHWs) with three to five fractures by the use of the basic theory of potential. First, the seepage model of fractured horizontal wells with infinite inflow fractures and the stable and unstable seepage models within the fractures are analyzed. Second, the distribution of potential and pressure was quantitatively simulated for a given gas reservoir (mainly 3–5 fractures), and the potential and pressure at any point were derived. Finally, the fracture parameters of the MFHWs were optimized in terms of two evaluation indexes, the average fracture production and the single well production by the use of an orthogonal test. The optimized fracture spacing is 100–150 m, and the longer the fracture width and fracture length, the better production performance. The research results have theoretical significance and provide reference for the selection of fracture parameters for horizontal wells in low-permeability gas reservoirs and the productivity evaluation of MFHWs.

Well Test Analysis of Inclined Wells in the Low-Permeability Composite Gas Reservoir Considering the Non-Darcy Flow

The application of traditional well test interpretation methods cannot comprehensively consider characteristics of stress sensitivity and non-Darcy flow for low-permeability composite gas reservoirs, which makes it difficult to obtain real reservoir parameters. Based on the micro-mechanism analysis of stress sensitivity and non-Darcy flow in low-permeability gas reservoirs, the flow motion equation was improved. Thus, a mathematical model was established which belongs to the inclined well in the composite gas reservoir with a conventional internal zone and low-permeability external zone. Applying the finite element method to solve the flow model through Matlab programming, the equivalent pressure point was selected to research the pressure distribution of the inclined well. On this basis, the bottom hole pressure dynamic curve was drawn, the flow process was divided into seven stages, and the parameter sensitivity analysis was carried out. Finally, the advanced nature of the new model applied to the interpretation of the well test model is compared by conventional methods. The non-Darcy flow can cause the gradual upward warping of the bottom hole pressure dynamic curve in the later stage, and non-linear enhancement leads to an increase in the upturn through the simulation test. When the inclination angle is greater than 60°, early vertical radial flow and mid-term linear flow gradually appear. A decrease leads to a shorter duration of the pseudo radial flow in the internal zone and the radius of the internal zone. The conduction coefficients ratio of internal and external zones affects the pseudo pressure derivative curve slope in transition phase of pseudo radial flow in the internal and external zones. A comprehensive consideration of the low-permeability composite gas reservoir flow characteristics can improve the fitting degree of the pressure curves. Not only that, but it can also solve the strong diversification of reservoir parameters. Results have a guiding significance for low-permeability composite gas reservoir development and pressure dynamic evaluation in inclined wells.

An Unsteady-State Productivity Model and Main Influences on Low-Permeability Water-Bearing Gas Reservoirs at Ultrahigh Temperature/High Pressure.

Currently, there is insufficient knowledge on the development of China’s low-permeability gas reservoirs under ultrahigh-temperature and high-pressure conditions; furthermore, the actual development process is difficult and has high technical demands. For example, the Ledong block in the South China Sea is a typical gas reservoir characterized using ultrahigh temperature (190 °C), high pressure (90 MPa), high water production, and low permeability (less than 1 mD). However, it is difficult to determine the factors influencing its production capacity, and the application of the traditional production capacity model is problematic because of the production of water. Accordingly, this study, which is based on the seepage theory, considers the influence of water production on the productivity of a single well; this study establishes an evaluation method for a low-permeability water-bearing gas reservoir vertical well (i.e., a highly deviated well) to determine how an unsteady state affects productivity. This method comprehensively considers stress sensitivity, initial pressure gradient, gas–water permeability, formation thickness, absolute permeability, supply radius, discharge radius, and well deviation angles to clarify the main factors affecting the productivity of single wells. Statistical methods are used to calculate and analyze the key influential factors, and this study provides quantitative evaluation methods to understand the productivity (and its influencing factors) of both vertical and highly deviated wells and the law of productivity decline. The model calculates the unblocked flow rate for 18 years as 319 × 104 m3/d. Compared with the actual production unblocked flow rate of 332 × 104 m3/d, the average error is 3.9%, which is within the allowed engineering range. Research shows the following order of factor influence on productivity: produced water–gas volume ratio > permeability > stress sensitivity coefficient > reservoir thickness > start-up pressure gradient > well deviation angle > discharge radius. Water saturation is the main factor affecting the unsteady-state productivity of gas wells in low-permeability gas reservoirs. In this study, with a production time of 100 days, the water saturation increases from 45 to 85%, and the open flow of the gas well decreases significantly from 30.1 × 104 to 1.6 × 104 m3/d, which is a decrease of 94.7%. Moreover, a continuous increase in the stress sensitivity coefficient, start-up pressure gradient, and water saturation caused a leftward shift in the inflow performance relationship curves of the modeled gas wells, whereas their production decreased.

Study on the effect of oligomer silicone surfactant on the properties of drilling fluids

Due to small hole roar, most of low-permeability gas reservoirs are water wetting, and the capillary effect is very prominent, resulting in water blocking damage in the process of exploitation for natural gas. A new kind of oligomer silicone surfactant (OSSF) was developed, and the physical and chemical properties of oligomer silicone surfactant were evaluated. The experimental results indicated that the critical micelle concentration of OSSF was 0.418×10-3 mol/L, and the critical surface tension of OSSF was 20.631 mN/m. OSSF could be adsorbed directionally at the water-rock pore interface, and the cores adsorbed with OSSF should reverse from water wetting to oil wetting or gas wetting. OSSF had good compatibility with sulphonated polymer mud. OSSF could play an important role in unlocking water blocking damage to increase production and efficiency.

Judgment of horizontal well liquid loading in fractured low-permeability gas reservoirs

In order to solve the problem that the wellbore liquid loading of low permeability horizontal wells can’t be predicted accurately in previous studies, this article establishes a new matrix - natural fracture - wellbore horizontal gas well productivity equation considering stress sensitivity, starting pressure gradient and high speed turbulence effect. The method is used to judge whether there is liquid loading in a gas reservoir, and verified by the critical liquid carrying flow method. The results show that the accuracy rate of predicting liquid loading by productivity equation method is 80%, and the accuracy rate of predicting gas well productivity is 91.55%. Meanwhile, the influence rule of natural fracture parameters on productivity is given and it is found that the stress sensitivity coefficient has little effect on productivity. At the same bottom hole pressure, the gas production gradually decreases with the increase of high-speed nonlinear coefficient and gas production gradually increases with the increase of the number and width of natural fractures. The findings of this study can help for better understanding of the relationship between wellbore liquid loading and gas well productivity, and then better grasping the timing of gas well drainage and gas recovery.

Research on Exploration System of Petroleum Geological Development Based on Oilfield Fracturing Technology

Oil and gas energy is one of the necessary energy sources for social development. In the process of oil development and exploration, hydraulic fracturing technology plays a vital role. Hydraulic fracturing technology can not only stabilize the production of conventional oil and gas fields, realize the development of low-permeability oil and gas reservoirs, help the development and adjustment of old oil fields, but also increase the development production of special oil reservoirs and tap the potential of oil and gas fields. In this paper, an electrical simulation experiment method for the productivity of horizontal well staged fracturing is studied. Firstly, according to the actual formation conditions after staged fracturing of horizontal wells, a set of three-dimensional electric field simulation device is simulated and developed; According to the wellbore trajectory, formation permeability and formation thickness, etc., the electrolyte and electrolytic cell size for electrical simulation are set. Finally, the current signal is collected to determine the size of the production capacity. Using this experimental method, we carried out the optimization simulation of horizontal well fracturing fracture shape and location, optimization simulation of fracture number and spacing, and comparison of different formation thicknesses for a fluvial facies sedimentary sand body. This electrical simulation experiment method can accurately simulate the influence of various parameters of horizontal well fracturing and completion on productivity, and has certain guiding significance for the design of horizontal well fracturing and completion.

Modified Horizontal Well Productivity Model for a Tight Gas Reservoir Subjected to Non-Uniform Damage and Turbulence

Tight gas reservoirs are finding greater interest with the advancement of technology and realistic prediction of flow rate and pressure from such wells are critical in project economics. This paper presents a modified productivity equation for tight gas horizontal wells by modifying the mechanical skin factor to account for non-uniform formation damage along with the incorporation of turbulence effect in the near-wellbore region. Hawkin’s formula for calculating skin factor considers the radius of damage as a constant value, which is less accurate in low-permeability tight gas reservoirs. This paper uses a multi-segment horizontal well approach to develop the local skin factors and the equivalent skin factor by equating the total production from the entire horizontal well to the sum of the flow from individual segmented damaged zones along the well length. Conical and horn-shaped damaged profiles are used to develop the equivalent skin used in the horizontal well productivity equation. The productivity model is applied to a case study involving the development of a tight gas field with horizontal wells. The influence of the horizontal well length, damaged zone permeability, drainage area, reservoir thickness, and wellbore diameter on the calculated equivalent skin (of a non-uniform skin distribution) and the flow rate (with turbulence and no turbulence) are investigated. The results obtained from this investigation show significant potential to assist in making practical decisions on the favorable parameters for the success of the field development in terms of equivalent skin factor, flow rate, and inflow performance relationships (IPR).