Rich Gas Condensate Reservoir Research Articles

Investigating the Behavior of Low Permeable Lean and Rich Gas Condensate Reservoirs

The producing behavior of low permeable gas condensate reservoirs is dramatically different from that of conventional reservoirs and requires a new paradigm to understand and interpret it. As the reservoir pressure initiates to decline and reaches to dew point pressure of the fluid then the condensate is formed and causes the restriction in the flow in the reservoir rock which results, decrease in the well productivity near the wellbore vicinity which is known as condensate blockage. Henceforward, it is better to understand the behavior of the low permeable lean and rich gas condensate reservoirs by several perspectives through the compositional simulator. Besides this study involves the following perspectives; the increase in the number of wells and by varying the flowrate of the gas in six different cases for low permeable lean and rich gas condensate reservoirs. It was concluded that low permeable lean and rich gas condensate reservoirs have similar gas recovery factors. Whereas the CRF plays inverse behavior for both reservoirs as CRF is maximum for lean gas condensate at single producing well but for rich gas condensate reservoir the CRF increases as the number of wells escalates. Additionally, in second effect the varying gas flowrates lean gas condensate reservoir has maximum CRF at lesser flowrate but it is opposite for the low permeable rich gas condensate reservoir, for single or two producing wells the flowrate effect plays but when the number of wells is increasing there is not any significant change in CRF

New forecasting method for liquid rich shale gas condensate reservoirs with data driven approach using principal component analysis

Accurate production performance evaluation and forecasting in shales during the early stages of development can play an important role in minimizing uncertainties associated with unconventional reservoirs. Given the limited reliability in forecasts from traditional decline models when applied to unconventional reservoirs, new tools to supplement the ones in use today are required to improve the accuracy of production forecasts. In this study, we present a method involving principal component analysis (PCA), which is a simple, non-parametric method of extracting relevant information from large data sets to perform production forecasting of liquid rich shale gas condensate reservoirs.We used a comprehensive compositional reservoir model to create several iterations of synthetic production histories from liquid rich shales (LRS) wells based on Monte Carlo simulation with predefined probability distributions. Cumulative gas, gas rate, and condensate-to-gas ratio (CGR) for the simulated cases were decomposed into principal component (PC) scores and coefficients were used to recreate the original data. The dataset was cross-validated to check its ability to predict the missing production data based on PC scores and coefficients of the limited production data. Principal component analysis was further applied to the field data from several wells from Eagle Ford shale. We re-created and cross-validated the field data by using limited PC which led to good matches of the original production data. Two to three PC's were required to recreate the initial data with reasonable accuracy depending on the quality of the input data. During the validation step, we observed that some of the wells exhibited significant error which could be attributed to significantly different production profiles of those wells compared to the other wells. For simulated data, four PC was enough to yield the prediction with average error of 0.16%, 0% and 0.77% respectively for gas rate, cumulative gas and CGR respectively. For field data, three PC yielded the best prediction with average error of 1.63% and 2.98% for gas rate and oil rate respectively.This work shows that multivariate statistics and data driven methods can be used as an important approach to complement existing tools like reservoir simulation and decline curve analysis to perform production data analysis. PCA can also be used and can generate accurate results relatively quickly. We recognize that even more rapid approximate methods will be required for routine analysis. Understanding the limitations of different approximate methods and application of methods to overcome these limitations in given circumstances should lead to optimal use of these methods.

Investigating the factor influencing the flow behavior and performance of condensate gas reservoirs

Well productivity is an important issue in the development of most low and medium- permeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region. When the well pressure falls below the dew-point, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing the well productivity. It is essential to take account of this condensate-blockage effect when calculating well productivity. Most of the pressure drop in a gas condensate well occurs close to the well walls. Because of the increase in pressure drop and the increase in flow rate, two additional phenomena get involved in gas flow control: The effect of positive coupling (due to increased capillary number) and the effect of inertia (due to non-Darcy flow). In many gas-condensate wells, the final result of these two parameters is improving well productivity, reducing the impairment caused by condensate blockage. Another phenomenon that can take place in high temperature gas reservoir is water vaporization. Pressure drop near well wall causes molar content of water in gas-phase to increase, therefore connate water starts to vaporize near the well walls. This change in connate water saturation near the well wall can influence well productivity by changing saturation of fluids near well walls. The effect of water vaporization on well productivity of gas and gas - condensate reservoirs are investigated by considering a single well one dimensional radial model simulation. The simulations show that water vaporization increases productivity of well by increasing gas saturation and relative permeability near the well walls and improving the mobility of gas; and this effect is stronger in rich gas condensate reservoir than the lean ones.

INVESTIGATING THE EFFECTS OF WATER VAPORIZATION ON THE PRODUCTION OF GAS CONDENSATE RESERVOIRS

Well productivity is an important issue in the development of most low and mediumpermeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region. When the well pressure falls below the dew-point, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing the well productivity. It is essential to take account of this condensate-blockage effect when calculating well productivity. Most of the pressure drop in a gas condensate well occurs close to the well walls. Because of the increase in pressure drop and the increase in flow rate, two additional phenomena get involved in gas flow control: The effect of positive coupling (due to increased capillary number) and the effect of inertia (due to non-Darcy flow). In many gas-condensate wells, the final result of these two parameters is improving well productivity, reducing the impairment caused by condensate blockage. Another phenomenon that can take place in high temperature gas reservoir is water vaporization. Pressure drop near well wall causes molar content of water in gas-phase to increase, therefore connate water starts to vaporize near the well walls. This change in connate water saturation near the well wall can influence well productivity by changing saturation of fluids near well walls. The effect of water vaporization on well productivity of gas and gas - condensate reservoirs are investigated by considering a single well one dimensional radial model simulation. The simulations show that water vaporization increases productivity of well by increasing gas saturation and relative permeability near the well walls and improving the mobility of gas; and this effect is stronger in rich gas condensate reservoir than the lean ones. Keywords: Well, Gas, Pressure Drop, Vapor pressure of water

Investigating the effects of water vaporization on the production of gas condensate reservoirs

Well productivity is an important issue in the development of most low and mediumpermeability gas-condensate reservoirs. However, accurate forecasts of productivity can be difficult because of the need to understand and account for the complex processes that occur in the near-well region. When the well pressure falls below the dew-point, a region of high liquid saturation builds up around the well, impairing the flow of gas and reducing the well productivity. It is essential to take account of this condensate-blockage effect when calculating well productivity. Most of the pressure drop in a gas condensate well occurs close to the well walls. Because of the increase in pressure drop and the increase in flow rate, two additional phenomena get involved in gas flow control: The effect of positive coupling (due to increased capillary number) and the effect of inertia (due to non-Darcy flow). In many gas-condensate wells, the final result of these two parameters is improving well productivity, reducing the impairment caused by condensate blockage. Another phenomenon that can take place in high temperature gas reservoir is water vaporization.Pressure drop near well wall causes molar content of water in gas-phase to increase, therefore connate water starts to vaporize near the well walls. This change in connate water saturation near the well wall can influence well productivity by changing saturation of fluids near well walls. The effect of water vaporization on well productivity of gas and gas - condensate reservoirs are investigated by considering a single well one dimensional radial model simulation. The simulations show that water vaporization increases productivity of well by increasing gas saturation and relative permeability near the well walls and improving the mobility of gas; and this effect is stronger in rich gas condensate reservoir than the lean ones.Keywords: Well, Gas, Pressure Drop, Vapor pressure of water

Analyzing the Facies, Sedimentary Environment, Sequence Stratigraphy and Diagenetic Processes of Kangan Formation in Kish Gas Field (Kish Well#3)

Background/Objectives: Although many studies have investigated the reservoir formations in Dahrom group including Kangan formation, but most of these studies have been concerned to other hydrocarbon fields. Regarding the great reservoir importance of Kangan formation in Kish Gas field, therefore, it is important to examine these rich gas-condensate reservoirs. This study aims to restore the sedimentation condition and the conditions governing the sedimentary basins during that period (lower Triassic) and detect the factors affecting the reservoir quality. Methods: To determine facies, sedimentary environment, sequence stratigraphy and identify the most important diagenetic processes occurring in the evaporate-carbonate depositions of Kangan Formation in Kish Gas Field, a sample of 510 microscopic thin sections were collected out of the core extracted from Kish Well#3 and considered by polarizan microscope. Results: Detailed petrographic investigation and well log analysis of the Kangan Formation in Kish gas field led to the recognition of arid tidalflat (A), back barrier lagoon (B) and barrier/shoal (C) facies belts related to an inner part of a homoclinal ramp platform. The Kangan Formation is mainly composed of dolomite, dolomitic limestone with shale and anhydrite. This formation has been affected by several diagenetic processes which played a significant role in improving reservoir quality. Conclusions: Vertical facies changes and cycle stacking patterns demonstrate that the Kangan Formation consists of four depositional sequences of the Third-order in the Kish Well#3, each consisting of transgressive and highstand systems tracts.

The Effect of Nitrogen Injection on Production Improvement in an Iranian Rich Gas Condensate Reservoir

In gas condensate reservoirs, after a decrease in pressure below the dew point pressure, condensate formation would occur. One of the common and practical methods for prohibiting the rapid pressure drop in the reservoir and reduction of liquid dropout is gas injection. In this study, experimental measurement, the full field reservoir model and an economical evaluation have been performed to investigate the effect of nitrogen injection on an Iranian Southwestern gas condensate reservoir. At first, swelling and CVD tests were carried out to determine the swelling factor and changing the saturation pressure by nitrogen. Then, the full field simulation (history matching and prediction) was performed and finally an economical evaluation has been made. The results show that injecting more volumes of nitrogen cause to decrease the liquid dropout, increase the dew point pressure, and condensate ultimate recovery, but this process is not an economical project.

Well productivity in an Iranian gas-condensate reservoir: A case study

This work is another step forward in our understanding of the dynamics of condensate buildup around wellbores in gas condensate fields. For this purpose one of the unique and huge Iranian gas condensate reservoirs is selected. The effects of condensate bank on the gas and condensate productivity and also the reservoir performance have been investigated throughout a simulation study. The productivity of the wells in the moderately rich gas condensate reservoir was observed to have initial rapid decrease and then reach a relatively constant value and after that a second decrease as the reservoir was depleted. Compositional simulation clarified the reasons for this uncommon productivity change. During early production, a ring of condensate rapidly formed around wellbore when the near-wellbore pressure decreased below the dew point pressure of the reservoir fluid. Moreover, relative permeability effects caused the saturation of condensate in this region to be considerably higher than the maximum condensate predicted by the PVT laboratory work. Gas productivity also decreased as the effective permeability to gas was severely reduced due to this high condensate saturation in the ring. After condensate formation throughout the reservoir due to pressure reduction below dew point, the gas flowing into the ring became leaner causing the condensate saturation in the ring to decrease. This increased the effective permeability of the gas. On the other hand, the reservoir pressure drop leads to less productivity which caused the gas productivity to reach a constant value. Changes in gas and condensate compositions in the reservoir also impacted gas productivity. As the result of this study it could be mentioned that the gas production rate may stabilize, decrease or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore which would decrease in the near wellbore region because of the leaner gas entering this region and also partial vaporization. In addition to the gas production rate, the composition change should also be considered in the sale contracts.

Natural Gas Compressibility Factor Correlation Evaluation for Niger Delta Gas Fields

Natural gas compressibility factor (Z) is key factor in gas industry for natural gas production and transportation. This research presents a new natural gas compressibility factor correlation for Niger Delta gas fields. First, gas properties databank was developed from twenty-two (22) laboratory Gas PVT Reports from Niger Delta gas fields. Secondly, the existing natural gas compressibility factor correlations were evaluated against the developed database (comprising 22 gas reservoirs and 223 data sets). The developed new correlation was used to compute the z-factors for the four natural gas reservoir system of dry gas, solution gas, rich CO2 gas and rich condensate gas reservoirs, and the results were compared with some exiting correlations. The performances of the developed correction indicated better statistical ranking, good graph trends and best crossplots parity line when compared with correlations evaluated. From the results the new developed correlation has the least standard error and absolute error of (stdEr) of 1.461% and 1.669% for dry gas; 6.661% and 1.674% for solution; 7.758% and 6.660% for rich CO2 and 7.668% and 6.661 % for rich condensate gas reservoirs. The new correlation also show high correlation coefficient of: 93.39%, for dry gas; 89.24% for solution gas; 83.56% for rich CO2 and 83.34% for rich Condensate gas reservoirs. Also the proposed new model maintained good graphical trends for four z-factors matched it: experimental, estimated (Standing - Katz) and the best evaluated correlation when matched. Very good crossplots parity line performance when compared with the evaluated correlations. It could then be concluded that the new developed correlation and that of Papay correlation are most appropriate correlations for calculating natural compressibility for Niger Delta gas fields. Carr, Kobayashi, and Burrows (1954) and Wichert-Aziz (1972), correction factor methods; were applied to correct the presence of non-hydrocarbons. But the major setbacks on laboratory analyses for PVT behavior are sometimes expensive and time consuming. Correlations, which are used to predict gas compressibility factor, are much easier and faster than equations of state, invariably save cost.

Huff 'n puff to revaporize liquid dropout in an Omani gas field

In this study, Huff 'n Puff technique is used as a production mechanism to revaporize liquid dropout in the Saih Rawl retrograde condensate gas field, Oman. During the huff cycle, a number of wells were shut in to achieve revaporization. The same wells were put on stream, during the puff cycle. Liquid dropout induced a mechanical skin around the wellbore and hampered gas production capabilities but has been revaporized through pressurization. The pressure buildup in the rich-gas condensate reservoir was due to a cross flow originating from a deeper highly pressurized lean-gas bearing formation. The pressure communication was taken place through the wellbore during shut-in cycles. A compositional simulation model was used to confirm the theory of condensate revaporization. Simulation results indicated that Huff 'n Puff is a viable production technique. The technique improved gas deliverability and enhanced gas–liquid production by minimizing the skin caused by gas–liquid dropout.

Long-Term Performance of Hydraulically Fractured Layered Rich Gas Condensate Reservoir

Compositional simulator has been used to investigate the effect of hydraulic fracture on the performance of a layered rich gas condensate reservoir in Saudi Arabia. The reservoir consists of five layers having permeabilities ranging from 0.08 to 115 md with about 68% of the gas reserve located in the lowest permeability layer. The fracture is assumed to penetrate all layers. The results of this investigation showed that hydraulic fracturing of such a reservoir is effective in improving the productivity of the gas condensate wells. The productivity index (PI) of the cases investigated was found to increase by as much as 3.6 folds. Hydraulic fractures were also found to delay the onset of the dew point pressure and consequently extend the production plateau above the dew point pressure. The production plateau above the dew point pressure was found to increase with increasing the dimensionless fracture conductivity. The results of this study also showed that once the dew point pressure is reached, the flowing bottom hole pressure was found to drop sharply to the specified minimum flowing bottom hole pressure in the fractured and nonfractured cases. However, the drop is less severe in the fractured case. This sharp drop in the flowing bottom hole pressure results in dropping the productivity of the gas condensate wells. Condensate build up along the fracture faces was found to be more significant in the high permeability layers. At early times after reaching the dew point pressure, the highest condensate saturation was found to be in the highest permeability layer. However, at late times (after reaching pseudo steady state) it decreased to a certain level above the critical condensate saturation. Finally, formation cross-flow is found to improve the productivity of the fractured and the nonfractured gas condensate wells. However, the improvement is more pronounced in the fractured cases.

Retrograde Condensate Dropout Phenomena in Rich Gas Reservoirs-Impact on Recoverable Reserves, Permeability, Diagnosis, and Stimulation Techniques

Abstract Gas condensate reservoirs exhibiting classic "dew point" or retrograde condensate dropout behaviour exist in many areas in the world. These reservoirs are unique in that, as the reservoir pressure is decreased, a certain volume of the heavy end fraction of the gas is precipitated in liquid form from solution in the gas. This condensate liquid may be temporarily or permanently trapped in the reservoir, causing severe reductions in gas production rates and the permanent loss of a large portion of the volatile and valuable condensate liquids (due to capillary pressure- induced trapping effects in the porous media). This paper reviews the basic theory of gas condensate dropout and describes, in detail, damage problems that may be associated with production of reservoirs of this type. Techniques for mitigating condensate dropout problems on a production basis, as well as stimulation techniques such as repressurization, lean and rich gas injection, surfactant and solvent injection, in situ combustion and water/gas injection, are reviewed, and the advantages and disadvantages of the techniques discussed. Introduction Rich gas or retrograde condensate gas reservoirs are common on a worldwide basis. Figure 1 provides a pressure-composition diagram for a typical hydrocarbon system at a fixed temperature level. The shaded portion of this figure represents an area of two-phase equilibrium at the specified composition and pressure condition. This is generally a region where an immiscible hydrocarbon liquid and gas phase co-exist in thermodynamic equilibrium. Outside this area is a single phase region, where only one continuous and homogeneous uniform phase exists. Potential Problems Associated with Rich Gas Condensate Systems There are two main categories of problems commonly associated with rich gas reservoir systems:Formation damage effects associated with the condensate dropout.Permanent loss of valuable light condensate liquids due to trapping effects in the reservoir. This paper addresses both of these issues and various techniques that can be used to reduce their impact on productivity and recovery. Formation Damage Issues in Gas Condensate Reservoirs The literature is replete with detailed discussions on formation damage(1–8). This paper does not address different types of damage which can occur during conventional drilling, completion and production operations, but concentrates solely on issues associated with condensate liquid dropout. The primary damage mechanism resulting in a reduction in gas production rate in a rich gas-condensate reservoir is generally associated with capillary pressure-motivated phase trapping effects. These effects result in permanent reduction in the effective permeability to gas in the region affected by the condensate dropout surrounding the wellbore. This phenomenon is illustrated pictorially in Figure 2 and using a set of gas-condensate relative permeability curves in Figure 3. As the condensate drops from solution in the gas while still in the porous media, capillary pressure effects are present [due to the generation of a second immiscible phase which has a finite interfacial tension (IFT) between it and the gas phase].

On the influence of fatigue on machine part wear: Bulatov, V.P. and Vedernikov, D.N. Water (1 Dec. 1993) 170(2), 167–173

This work is another step forward in our understanding of the dynamics of condensate buildup around wellbores in gas condensate fields. For this purpose one of the unique and huge Iranian gas condensate reservoirs is selected. The effects of condensate bank on the gas and condensate productivity and also the reservoir performance have been investigated throughout a simulation study. The productivity of the wells in the moderately rich gas condensate reservoir was observed to have initial rapid decrease and then reach a relatively constant value and after that a second decrease as the reservoir was depleted. Compositional simulation clarified the reasons for this uncommon productivity change. During early production, a ring of condensate rapidly formed around wellbore when the near-wellbore pressure decreased below the dew point pressure of the reservoir fluid. Moreover, relative permeability effects caused the saturation of condensate in this region to be considerably higher than the maximum condensate predicted by the PVT laboratory work. Gas productivity also decreased as the effective permeability to gas was severely reduced due to this high condensate saturation in the ring. After condensate formation throughout the reservoir due to pressure reduction below dew point, the gas flowing into the ring became leaner causing the condensate saturation in the ring to decrease. This increased the effective permeability of the gas. On the other hand, the reservoir pressure drop leads to less productivity which caused the gas productivity to reach a constant value. Changes in gas and condensate compositions in the reservoir also impacted gas productivity. As the result of this study it could be mentioned that the gas production rate may stabilize, decrease or possibly increase, after the period of initial decline. This is controlled primarily by the condensate saturation near the wellbore which would decrease in the near wellbore region because of the leaner gas entering this region and also partial vaporization. In addition to the gas production rate, the composition change should also be considered in the sale contracts.

A New Depletion-Performance Correlation for Gas-Condensate Reservoir Fluids

Abstract This paper presents the depletion-performance correlations developed using data from PVT studies and well-completion tests of 27 rich gas-condensate and volatile-oil reservoir fluids. The PVT behavior for each fluid was determined experimentally in the laboratory, and the depletion performance of each fluid was then calculated. Well-completion test data consisting of reservoir pressure and temperature, initial total gas-oil ratio, and stock-tank oil gravity were used with the depletion-performance data to develop general performance correlations. Three correlations are presented. The first equation shows the empirical relation of gas in place per barrel of hydrocarbon pore space with reservoir pressure and temperature, and initial total gas-oil ratio. The second equation is the correlation of stock-tank oil in place per barrel of hydrocarbon pore space. The third equation relates stock-tank oil production (to 500-psia depletion pressure) with pressure, temperature and oil gravity. All three correlations are also presented in convenient graphical form. Gas production to 500-psia depletion pressure is approximately 92.6 per cent of the gas in place for each fluid, so no correlation was developed for gas production. Introduction The rate of discovery of shallow, low-pressure and low-temperature oil reservoirs in the United States has been declining in recent years. For this reason, the search for oil gas gone to greater depths where high pressures and temperatures are encountered. A high-pressure and high-temperature reservoir is the environment in which many rich gas condensates and highly volatile oils are found. Because of this trend, the performance prediction of such reservoirs has become an important task of the reservoir engineer. The need and usefulness of a performance correlation based on field data that are available from the usual well-completion tests have previously been established.6 These earlier attempts have shown that the phase behavior of rich gas-condensate systems and volatile-oil and temperature.1 However, very little information on gas-condensate depletion performance5 was available at the time of these earlier attempts. The available of more recent data has made possible the development of an improved correlation. The data, as listed in Tables 1 and 2, are for 25 gas-condensate and two volatile-oil systems that were studied. The problem was to correlate the data for in-place fluids and the production data with the initial total gas-oil ratio, initial reservoir pressure and temperature, and stock-tank oil gravity. These correlations were obtained by multiple regression analysis, whereby the data were fitted to an equation by the method of least squared error.4 Basis of the Correlations The data used in the development of these correlations were obtained from depletion-performance calculations6 and well-test or production measurements. All of the independent variables used in the correlations are available from the usual well-test completion data. The reservoir volume considered is 1 bbl of hydrocarbon pore space (HCPS). The gas-oil ratio used is the total standard cubic feet of gas (at 14.7 psia, 60F) coming off the entire separator train per barrel of stock-tank oil. This minimizes the effect of separator conditions which might vary from system to system.

Aspects of Gas Deliverability

Abstract Three aspects of gas deliverability are presented in this paper. The first treats with the gas deliverability or availability of a normal depletion-type dry gas field. Such encompasses not only the period of stabilized constant rate, but in ore so, the "tailings" when a fixed abandonment pressure is reached and the rate by necessity must decline. A comprehensive work plot is offered, developed from mathematics herein included, that removes the trial-and-error computations that attended such undertakings in the past. The second part treats with the discount factor of the open flow potential constant from what is observed initially in testing a gas well to what is evidenced when stabilization is reached. This prevails in tight formations, such as the Kansas Hugoton field which is offered as the example. The means of establishing this factor are pressure build-up curves which, as sustained by analytical deductions, reproduce this entire period of transient flow under conditions of a constant rate influx. Finally, what is offered in this paper is the deliverability performance of an exceedingly rich gas condensate field producing from a tight formation. The example shown is the Knox Bromide field in Oklahoma, producing from the Bromide formations. The results are ominous, showing early reduction in permeability to gas flow, due to the retrograde condensate forming in the pore space, with the attending early logging-up of these wells. The analytics of lowered permeability are incorporated in the gas deliverability formula along with the PVT data that gives the increased condensate liquid saturation as the gas flows to the wellbore. This paper would not be complete without a critique offered at the end. With the many gas wells now in production and those that have completed their life, there has been no factual information collected by any source as to what constitutes that permeability range where a gas well would be unimpaired in its gas deliverability by the presence of rich condensate content, and the lowered range where such would be harmful. This question confronts all producers. Introduction Various aspects of gas deliverability are presented in this paper that includes depletion-type reservoirs, deterioration factor of the gas deliverability constant, and the performance of a rich gas condensate reservoir producing from a tight sand. With respect to the presentation of gas deliverability and its tailings for depletion-type gas reservoirs, one notes that this is essentially the information offered by every gas transmission company and producer appearing before the Federal Power Commission for Letters Of Conveyance in the dedication of reserves. In the ordinary procedure, as many engage upon this study, trial-and-error calculations are included, particularly as apply to the tailings. For many years one of the writers has employed mathematical analyses to perform this step and avoid the complexities so associated. In the preparation of this paper these analyses have been amplified to include any slope n for the open flow potential relationship for which the tailings can be determined from Fig. 1.With reference to the deterioration or discount factor of the open flow potential constant as such occurs in the gas deliverability formula, this for the most part has been an unexplored subject. Although the issue first appeared in the Kansas Hugoton field, where such was surmised but only recently resolved, this situation of a deterioration of the gas deliverability constant can occur wherever dry gas production from a tight sand is encountered. The first concerted attacks upon this problem were the presentations of Hurst and Goodson before the Kansas Corporation Commission to show that transient fluid flow and unsteady-state flow formulas prevailed. This was amplified later before the Federal Power Commission to show that this deterioration factor could be identified from pressure build-up curves. This has been reported by McMahon. Its importance to the industry merits the review of these essential features in completing the program on the aspects of gas deliverability. Finally, as illustrated here, for a low permeability formation such as the Knox Bromide field where the gas is rich, representing some 165 bbl of condensate per MMcf of effluent gas, the gas deliverability can be of limited extent in the life of the field, leaving substantial amounts of condensate and gas unrecovered. In cases such as this, gas cycling is mandatory. This is particularly revealed by the fluid mechanics introduced here, employing factual field as well as laboratory data, to show this restriction upon gas deliverability. JPT P. 668^