Water production or cross flow during production phase is highly undesirable as it incurs additional costs of water handling at surface and reduces relative permeability of hydrocarbons to flow. Problems associated with water production or its cross flow escalate in depleted and HT wells limiting water shut-off options. Long-term zonal isolation to prevent unwanted fluids and cross flow is challenging in such wells due to the need of proper placement in the targeted zone, compatibility of fluid/tool with the downhole temperature and its sustainability. The use of mechanical plugs including packing elements have limitation of application in some instances due to high temperature and odd sized tubulars. Having the abovesaid limitations, an engineering solution was made by testing and implementing reinforced Polymer Gel (a polymer-based gel loaded with silica sand) providing right angle set properties upon exposure to the given temperatures. The aforesaid combination produces a rigid, robust gel structure ideal for shutoff treatments into fractured, vugular and high permeability formations. Such gels can penetrate deep into the matrix or small fissures where the mechanical packers cannot reach to shut off the excess water. This paper demonstrates the assessments to counter above challenges and application of re-enforced temperature activated anionic polymer for water shut off in candidate wells in Southern & Northern regions of Pakistan.

Formation damage associated with water blockage is a common problem in oil/gas producing wells. Water blockage is a damage mechanism which occurs when water saturation increases near wellbore, resulting in reduced hydrocarbon saturation and relative permeability to gas. When pore spaces around the well get nearly saturated with water, it reduces gas saturation to near irreducible level that block the gas flow. It decreases the gas production and may recover naturally by extended flow back or excessive drawdown. However, in depleted reservoirs, gas production may completely be lost and shall require chemical treatment. In this paper, a case study has been presented illustrating the complete loss of production of a gas well owing to the water blockage and the treatment mechanism to restore the production (SPE 102383). Well ‘A’ was drilled in Sindh, Pakistan in 2010 in Lower Goru Formation. Later, the well was put on compression and was found on natural decline. By Feb 2019, well was producing 1.14 MMSCFD gas, 6 BPD condensate, and 43 BPD water with 123 psi FWHP. In March 2019, well was shut-in for the pressure build-up (PBU) survey. However, when the well was opened to flow, there was complete loss of production. Identification of the causes of production loss was a major challenge in designing the job. After analysis of well behavior, gradient survey data and formation properties, it was found that the loss of production was attributed to water blockage caused by prolonged exposure of water. Based on above analysis, a stimulation treatment using Volatile Acid System was designed to address the water blockage. The improved cleanup with volatile acid can be expected for two reasons; (1) increased volatility and (2) lower surface & interfacial tensions (SPE-191292-MS). The increased volatility results in lower water saturation and improving relative permeability to gas. Volatile acid system lowers the surface tension and increases the vapor pressure (gas saturation/relative permeability of gas near the damaged zone) and improves the clean-up of spent acid and retained water. In addition, presence of alcohol in acid system helps in achieving deeper penetration into the rock matrix. The proposed solution of Volatile acid system proved successful not only in reviving well's production but also with a gain in production of about 300%.

In Potwar Basin, Tight Naturally Fractured carbonate reservoirs usually have matrix porosity of the 2-3% and permeability less than 1 mD. It is very challenging to evaluate Gas initial in-place (GIIP) and reserves accurately in these type of reservoirs. The objective of this study is to evaluate Gas in-place and to characterize the reservoir energy mechanism using rate transient analysis (RTA). A comparison has also been made for Gas in-place from conventional material balance analysis and from rate transient analysis. In this study, rate transient analysis has been performed in a well, located in Potwar with thirteen years of production history. The well is completed in Chorgali and Sakesar formations. Different scenarios of initial reservoir pressure, geo-mechanical effects during initial production of the well and aquifer volume were sensitized to evaluate the Gas initial in-place (GIIP) and reserves. Different type curves such as Agarwal Gardner, Blasingame and flowing material balance and analytical aquifer modelling with / without geo-mechanical effects were applied and matched with the production history. Production logging data was also incorporated in the study. During history matching (gas-rate and bottom-hole flowing pressure), different sensitivities were run to quantify the uncertain parameters and level of uncertainty in the simulator. While history matching and evaluating GIIP/reserves, it was observed that 8,060 psi reservoir pressure measured in the well was not stabilized and the reservoir was dominated initially by geo-mechanical effects. The best match was achieved with 10,935 psi initial reservoir pressure which was measured in the first well of the field. Without considering this pressure and geo-mechanical effects, the best match could not be obtained. It was also confirmed by different type curves that reservoir was geo-mechanically pressured during the early life of the well and also, it has a weak aquifer support during the late life of the well. The GIIP evaluated from these type curves are in the range of 75-90 BSCF whereas conventional material balance showed 60-70 BSCF indicative volume associated with the well. This study exhibited a significant difference in GIIP/reserves evaluated from conventional material balance and rate transient analysis, indicating remaining hydrocarbon potential in the region i.e. approximately 10-13 BSCF. If the static reservoir pressure is taking too long to stabilize, the conventional material balance approach always depicts lower hydrocarbon volume associated with the well due to the tight and heterogeneous nature of the reservoirs. Therefore, conventional material balance cannot be applied in these reservoirs and unconventional approach such as rate transient analysis should be applied to evaluate GIIP / reserves and reservoir energy mechanism.

Hydraulic fracturing and drilling are commonly and widely used in many formations, particularly in unconventional reservoirs, such as tight sandstone reservoirs and so on. Whereas, during the fracturing or drilling process, large quantities of fluids are lost in the formation. Specially, many gas wells suffer a loss in productivity as a result of liquid invasion into the rock matrix. Liquid invasion is referred to as "water blocking", which is the primary damage that occurs in tight reservoirs and in low-permeability and ultra-low-permeability reservoirs. Some methods and materials, like methanol, are used to eliminate "water blocking", but only providing a temporary solution to the problem. This paper introduces a hydrophobic wettability function and mechanisem that effectively eliminates "water blocking" on the tight sandstone. The results from wettability experiments using tight sandstone show that hydrophobic wettability function on the sandstone surface, making a contact angle greater than 90°. The inner wall of capillary tube changes wettability and the capillary pressure becomes a positive driving force rather than a negative resistance. The experimental studies demonstrate that altering the wettability of tight sandstone to produce a hydrophobic surface is a viable method for recovering permeability and eliminating "water blocking".

Predicting the effects of the fracture penetration ratio and fracture conductivity in hydraulically- fractured vertical wells in dry-gas and wet-gas reservoirs is important in determining the well performance in a given formation. A fracture length and conductivity which provide the highest ultimate gas recovery factor at the earliest time to reach abandonment conditions is the proper fracture type which has to be selected for developing the reservoir. A three dimensional reservoir simulation model is used to evaluate the performance of hydraulic fractured vertical wells as a function of fracture penetration ratio and fracture conductivity. Accurate determination of initial gas reserves, average reservoir pressure at abandonment time, and the time to reach abandonment conditions is very important to the petroleum industry. Material balance technique and volumetric method, currently used in the petroleum industry to determine the reserves, which do not consider well performance and, as a result, predict a very high recovery factor at abandonment pressure for hydraulic fractured vertical wells in volumetric dry-gas and wet-gas reservoirs. Well performance in hydraulic fractured vertical wells depends on fracture penetration ratio and fracture conductivity. A comparison with horizontal wells of same penetration ratio is also provided in this paper as an alternative to hydraulic fracturing. A number of simulation runs were performed on a square shape reservoir of horizontal permeability 0.01 md, 0.1 md and 1 md with a penetration ratio of 0.2, 0.4 and 0.8. Our results quantify and show that the ultimate recovery factor and abandonment time are function of fracture penetration ratio regardless of fracture conductivity. In addition, our results shows that in low permeability reservoirs a hydraulic fractured vertical well of similar penetration ratio to a horizontal well perform twice in terms of recovery factor and abandonment time. The effects of formation thickness, well parameters and reservoir rock properties on the average reservoir pressure at abandonment time and on the time to reach the economic limit are also presented in this paper. Based on the results of fracture penetration ratio and fracture conductivity in volumetric dry-gas and wet-gas reservoirs, this paper presents recommendations regarding the proper well type with which the reservoir should be developed.

Water blockage is a common phenomenon that significantly deteriorates well deliverability. It is caused by introduction of external water in critical matrix which changes parent saturations thus damaging relative permeability to oil or gas. This paper discusses the case of a gas well that suffered complete loss of production due to water blockage which, however, was later successfully treated and revived using alcohol based recipe. The well K-1 was drilled By UEP in Sindh, Pakistan and encountered hydrocarbon hearing BS-1 and BS-2 Sands. The well was put on commingle production from BS-1 & BS-2. After few months of production, water breakthrough was observed from BS-2 and was subsequently isolated, based on production logging results, using mechanical plug. However, well behavior indicated integrity issue of mechanical plug with well ceased to flow from BS-1. Attempts to revive the well proved futile as K-1 did not revive. Detailed investigations identified that well loaded up due to cross flow of BS-2 water into BS-1 resulting in water blockage. In order to treat water blockage, alcohol based system was used. It is a volatile non-aqueous solvent which basically lowers the surface tension of acid and thereby achieves deeper penetration into rock matrix. Alcohol based recipe proved successful in curing water blockage and reviving the well's production.

Creating reservoir model that is accurate requires extensive data and enormous computing resources. As these resources are often not available, this study proposes a workflow (& corresponding case study) to generate box reservoir models that require minimum data yet yield reasonable results. Field Lima has two wells Lima-1 & Lima-2 (down-dip well) that produces gas from Sand-B which is a moderate water drive reservoir. After producing gas naturally, Lima-2 watered-out while Lima-1 still produced gas. To curtail the increase of Water Gas Ratio (WGR) in Lima-1, a coproduction technique was evaluated. The intent was to produce water from Lima-2 at high rates to reduce WGR increase in Lima-1. This required reservoir simulation to predict if producing water from Lima-2 will limit aquifer encroachment at Lima-1 and justify the additional CAPEX required to install water handling facility at Lima-2. As Lima is a marginal field, available dataset only included; initial reservoir pressure, production history and standard open-hole logs. No permeability, aquifer or pressure history data was available. Therefore, a workflow was formulated to create a reservoir model that can predict production rates of Lima-1 using available data within engineering accuracy. Firstly, the pressure history was created using recorded flowing wellhead pressures and wellbore hydraulics model. Further, a tank model was created for the reservoir using material balance software and cumulative productions of both wells were used as unique data to calibrate the model. This was used to calculate the aquifer properties. Fractional flow models & Corey correlations were used to estimate relative permeability data. All this derived data was then used as input in the reservoir simulator, where a localized block grid was created using depth-structure maps of Sand-B. The model was history matched using production data of Lima-1 & Lima-2 and aquifer movement was calibrated using water breakthrough in Lima-2. Finally, the model was run to predict production rates of Lima-1 with & without keeping Lima-2 on production to evaluate if co-production technique was effective. The model predicted that Lima-1 will be able to deliver its production targets even without keeping Lima-2 on production suggesting that extra CAPEX required for co-production was not justified. Forecasted gas rates for Lima-1 matched the actual gas rates with around 10% error. The accuracy of forecasted results endorses the use of box reservoir models to undertake economic decisions, in scenarios where lack of time & data doesn’t allow creation of detailed dynamic reservoir models.

It is normally understood in the industry that permeability and porosity are related but relationship can be strong or weak based on heterogeneity, anisotropy and lithology of the reservoir. So far linear models have been arbitrarily being tried to fit and matched with the data thereby resulting in a poor relationship. This paper seeks to explore data mining techniques for pattern recognition including Kohonen self-organizing maps and other unsupervised learning techniques. Kohonen self-organizing maps and principal component analysis are applied over permeability –porosity data to first cluster the data into various sets. This data can then be linked back to the formations and a predictor can be built thereby giving a tool for reservoir characterization. Then a linear model is to be built with the linearity being assessed by Shapiro Wilk Test and Quantile – Quantile (Q-Q) plot. This technique develops a relationship with a much better fit between permeability and porosity in respective ranges and thereby creating a higher cue-efficient of determination i.e. R squared value.

Forecasting the performance of individual wells is of great importance to oil companies for continuous field production optimization and cost per barrel reduction. Well Performance is measured by evaluating the Inflow Performance & Outflow Performance Relationships (IPR & OPR). For that the need to use the correct IPR for subjected reservoir is very essential. Since many decades, Vogel IPR equation has been used comprehensively for evaluating the productivity of vertical wells in saturated gas drive reservoirs. Vogel's model successfully evaluates IPR for single porosity solution gas drive in homogenous reservoirs. However, the applicability of Vogel's IPR for naturally fractured dual porosity-dual permeability reservoirs is questionable; hence this challenge is addressed by the industry only numerically. Due to composite fluid flow behavior between fracture and matrix system in a dual porosity-dual permeability reservoir, there is a pressing need for a new, practical and simple IPR model that takes into account the consideration of fracture parameters. This study investigates the effects of reservoir complex fluid flow behavior on IPR curves for vertical wells drilled in naturally fractured oil saturated reservoirs resulting in the development of an IPR curve for such conditions. A base case simulation model is developed with typical reservoir, fluid and rock properties using black oil model. Using a set of points relating oil production rates to flowing bottom-hole pressures, the dimensionless IPR curves are generated. Fluid and reservoir properties were varied between two porous and permeable media such as Inter-porosity flow co-efficient, storativity ratio, oil gravity, reservoir thickness and bubble point pressure. Inter-porosity flow coefficient and fracture storativity ratio were found to have a significant impact on dimensionless IPR curves. Finally, an attempt is made to converge the results into one simple model using non-linear regression technique in order to get a new empirical IPR correlation for vertical well producing from naturally fractured oil reservoirs. A small and acceptable average absolute error of less than 2% was found with the new proposed empirical IPR model, while comparing the existing published correlations on the same data gives more than 15% error. The developed IPR correlation is accurate enough and can serve as a handy tool for the production engineers to forecast the productivity of wells drilled in a naturally fractured dual porosity-dual permeability saturated oil reservoirs.

Relative permeability and interfacial tension are key parameters to characterize chemical enhanced oil recovery. Chemical flooding, a modern technique of enhanced oil recovery is based on the principle of reduction in interfacial tension of oil/water system. The selection of suitable surfactant is important and it should be compatible in a single phase solution at reservoir conditions and can be capable of reducing the interfacial tension to about 10–3 dynes/cm. In this study, Alcohol Alkoxy sulfate sodium salt (AAS) has been used as a surfactant. AAS was found compatible for conducting core flood experiment and it also reduced the oil/water interfacial tension to a very low value by forming type III micro emulsion. A Berea sandstone core plug of 100md was used in the core flooding experiment. The experimental results showed significant decrease in water/oil interfacial tension of 29 dynes/cm to 4.15*10–4 dynes/cm. SendraTM estimation was used for the history matching between experimental data with simulated one. Recovery with water flooding was 59.28%, whereas with surfactants it was increased to 85.95%. Relative Permeability of oil was 0.92 with water flooding, whereas relative permeability of oil with surfactant flooding was 0.98. The comparative analysis showed that two phase region (oil-water) becomes wider when surfactant was used and also relative permeability of oil was increased with decrease in interfacial tension. This study shows that surfactants can be applied in most oil fields of Pakistan especially in Central Potwar region where oil API is in the range of 10–22◦, so they promise a bright future for Petroleum Industry in Pakistan.

Worldwide, the high water production along producing hydrocarbons is affecting the cumulative productivity of wells. Due to complex reservoir parametric changes during the production, the near-by water aquifers or water tables infiltrates highly into the reservoir and starts affecting the well's productivity. Controlling the high water-cut producing wells is very challenging in the petroleum industry and is of prime importance as high water cut wells sometimes creates the mechanical and chemical damages to the equipment, depending on the water composition. The research is focused on using one of the most effective and economical chemical treatment method. The Colloidal Dispersion Polymer Gel (CDPG) is injected from the injection well into the reservoir having very high the water cut. CDPG injection attempts in increasing the water viscosity, decreasing its mobility towards producing well that results in increasing the reservoir's oil productivity. CDPG injection results in oil increment and reduces 21% water-cut whereas initially it was 78% and now it is 57%. That much amount of water if produced will cost huge techno-economics and increment oil will prominently help to increase profit.

It is a well-known fact that the deliverability of condensate reservoirs is a function of condensate formation around the wellbore. Thus, accurate estimation of condensate recovery necessitates properly modeled Equation-of-State (EOS) and subsurface flow phenomena. EOS is a function of numerous parameters of the Reservoir and Fluid contained; however it should be kept in mind that it is almost impossible to exactly match all these parameters, while all the parameters don’t obligate equal significance as well. This paper describes the most important parameters in EOS which ultimately control the overall condensate recovery. It involves unique simulation methodology to determine the condensate flow in reservoir using velocity-dependent-relative-permeability (VRP) curves (instead of conventional-relative permeability methods) to determine the effect of velocity stripping near the well bore; and the Pseudo-pressure approach. The modified form of EOS used in the study, along with the VRP curves features accurate condensate flow in the reservoir and its optimization. Moreover, using the pseudo pressure approach, this paper also signifies the reservoir modeling and forecasting methods with minimum amount of time for simulation. A complete and comprehensive strategy has been presented in this paper, to infer the factors having max influence on recovery. Using diverse sensitivities, it is evident that four parameters have a high influence; which includes compositional-variation with depth, Liquid drop-out, Condensate viscosity and Compressibility, while the rest yield minimal impact. The VPR models also improve history matching and give better forecast; while using pseudo-pressure approach reduces significant time with negligible impact on the results.

Most studies on reservoir characterization and evaluation have concentrated on identification of depositional facies based on the assumption that depositional characteristics and diagenetic features control the petrophysical properties. In sandstone reservoirs, this assumption is usually valid but may be applicable only locally. In this case study, there were discrepancies in the depositional facies at various well locations with their porosity and permeability ranges overlapping each other and therefore hydraulic rock typing approach was adopted in the area of interest. Facies identification plays a key role in permeability and saturation height modelling, and therefore has the basis in the physics of flow at the pore network scale. This basis is best achieved by seeking functional relationships between core derived pore throat parameters and macroscopic petrophysical attributes such as porosity and permeability when rocks of similar fluid conductivity are identified and grouped together. Each such grouping is referred to as a Hydraulic Flow Unit (HFU). HFU methodologies were used on the data set such as Winland R35 and Pittman (1992) , and discovered that the effective pore system that dominates flow through the pore system of interest corresponds to a pore throat size at which the mercury saturation is 45%. Using Pittman R45 equation, 4 sets of facies were identified on the poro-perm plot. The klinkenberg and net over burden corrections were applied on porosities and permeabilities before performing the analysis. The appropriateness of facies classification was determined with comparison of permeability and saturation prediction with core permeabilities and log saturations respectively. Saturation height methods such as Leverett J Function, Brooks Corey, Thomeer and Lamda were investigated for the gas wells under study, which had complete data sets including conventional core, SCAL and a comprehensive suite of electric logs. This paper demonstrates the effectiveness of HFU methodology for the field case under study. It also highlights the aptness of facies identification for the subject field using different saturation height methods, discussing their pros/cons in course.

As a matter of general belief there does not exist a universal mathematical relationship between porosity and permeability. Common practice to draw relationship between these two parameters is usually graphical, for instance using picket plots or picking general trends in the core or well logs data. Trends picked are mostly explicit and subjective i.e. limited to well and cannot be extrapolated to full field if the degree of heterogeneity is significant. Core work presents a general rigorous procedure for deriving a linear mathematical model for predicting permeability given porosity and vice versa, using statistical methods i.e. regression analysis & probability distribution, is developed using appropriate core data. Based upon the literature review to the best of our knowledge so far regression analysis presented between porosity & permeability is so shallow and is only limited up to drawing trends in core or well logs data. Whereas in this paper, application of standard regression analysis methods opted from statistics is discussed in more details. In this regards the utility of Shapiro-Wilk test, Quantile-Quantile (Q-Q) plot, Cook's distance and residual plots have been presented to deal with outliers which normally come from heterogeneity. These techniques ultimately help developing a linear mathematical model for prediction. Besides in any new oil & gas field for reserves calculation and production forecast usually average porosity and permeability is needed. However, for best estimates average values for porosity & permeability have been calculated using probability distribution techniques. Average values obtained are more reliable than those obtained using simple averaging methods thus relatively more precise estimates of reserves/resources and production forecast can be made.

As more technologies to enhance oil production recovery are being developed, well stimulation has been introduced and it acts as one of the important roles to fulfil the demand of world for energy. Well stimulation is a well intervention performed on an oil or gas well to increase production by improving the flow of hydrocarbons from the drainage area into the well bore. Well stimulation generally uses fluids which create or enlarge the flow channels of formation so that it can overcome low permeability of formation. A most common and one of the most successful well stimulation is matrix acidizing. In matrix acidizing, acids are injected at matrix pressure below formation fracturing pressure. The permeability of formation will be increased either by removing the pore-plugging materials in the formation or by creating new or enlarged flow paths in the rock depending on the formation and acid types. The right type of acid or combination of acids must be used to remove the damage. Thus, careful acid choice and treatment design are critical for a successful matrix acidizing. This paper presents the results of laboratory investigation of different acid combinations: HF/HCl, HF/HCOOH, HF/H 3 PO 4 , HBF 4 /HCl and HBF 4 /HCOOH. Hydrofluoric acid and fluoboric acid are used to dissolve clays and feldspar, while hydrochloric acid, phosphoric acid and formic acid are added to control the speed of reaction to allow the maximum acid to penetrate the core sample and also act as a buffer to maintain pH of the solution. Different tests have been performed on the core samples before and after the acidizing to do the comparative study. The results analyzed are permeability, porosity, color change, strength and mineralogy. Most of the new combinations used in this research showed better results than mud acid. But overall it is clear that in coming future lot of work can be done on sandstone acidizing prospects.

It has long been proved experimentally that the tight gas sands are more pronounced to stress changes as compared to moderate and high permeability reservoirs because of the narrow flow channels of the formation [ 1 ]. The consideration of the effect of stress in the evaluation and production performance of tight gas reservoirs is very important in order to make right decisions regarding their development. Due to hydrocarbon production, the effective stress increases causing a reduction in permeability and porosity of the porous medium. The conventional pressure transient analysis techniques in gas wells based on constant permeability would become unreliable [ 2 ]. Consequently, the incorrect evaluation of permeability leads towards wrong decision regarding well stimulation. Also the inflow performance modeling of tight gas reservoirs based on constant permeability will not be corrected as far as evaluation of well's production potential is concerned. Few studies on tight gas reservoirs considering the effect of stress sensitive permeability used the Raghavan's stress dependent pseudo-pressure approach [ 3 ] for which pressure vs. permeability data was determined experimentally. But, if laboratory data is not available then there is need to develop an analytical approach to generate the pressure vs. permeability data required for the use of stress dependent pseudo-pressure in reservoir evaluation and production performance studies in tight gas reservoirs. The objective of this paper is to develop an analytical approach, in the absence of lab data, to generate pressure vs. permeability data for the determination of stress dependent pseudo-pressure. This stress dependent pseudo-pressure is used for well test analysis to determine the stress sensitive formation permeability and also to generate production performance in tight gas reservoirs. The developed technique has also been implemented on the field data of a tight gas reservoir tovalidate the results by using actual well's production history.

The demand of energy in Pakistan is increasing continuously. Fossil fuel mainly coal reserves more than 175 billion tons in the Thar can play a vital role to fulfill energy needs for decades. The Thar Coal field was discovered in 1992 but up till 2010 no serious efforts were made to utilize this huge energy resource. In 2010 Underground coal gasification project was established to develop and exploit the thar coal deposits with underground coal gasification (UCG) technique to convert the in-situ coal to syngas for power generation and for other industrial uses. During construction phase of the underground coal gasification different problems were encountered mainly the hole linkage, water incursion, aquifer characterization and ignition of coal. This study provides the research work made in the field to solve above mentioned problems and presents detail analysis and procedures that how these problems were meet and solved. Finally this study presents characterization of the aquifer and shows from which well ignition should start to produce syngas from Thar coal.

Exploration and exploitation of low permeability gas reservoirs in mature developed field is a challenge. It involves re-evaluation and characterization of reservoir properties of the producing zones. As the field understudy is mature and needs to understand the different pressure regimes and available gas potential in depleted and un-depleted zones before embarking on the exploitation of these low permeability reservoir. In past, development of low permeability reservoir was considered uneconomical due to low flow rate and longer pay out time. However, present gas prices and existence of infrastructure of surface facilities on field shifts the negative economics of low gas flow rates to positive direction. Consequently, any gas flow rates are deemed to be economical and a source of extra revenue. In this field, both carbonate and sandstone are producing reservoirs. Carbonates are of low permeability reservoir while sandstone is fragile and represent high permeability reservoir. Initially DSTs were conducted in both reservoirs while wells were completed in sand stone reservoir. Due to the fragile nature of the sandstone formation, gravel pack completion was used to avoid sand production. Initially, high permeability sand stone formation was produced. Volumetric and dynamic data was collected and analyzed to determine the undepleted part of the reservoir. The dynamic data indicated that low permeability reservoir has insignificant contribution and needs to be developed. Petrophysical properties of the carbonate reservoir were reviewed; new DST was conducted in the carbonate reservoir. During DST, longer build up was planned for reliable pressure data. After DST analysis, it was observed that it is low permeability reservoir with high skin value and need to be stimulated. Acid stimulation was carried out that have resulted in significant improvement and the well was put on production with sustainable production rate. In this paper, integrated approach of evaluation of geological and dynamic data that have resulted in successful recompletion of wells in low permeability carbonate reservoir will be discussed. The lesson learned from this successful evaluation and production of low permeability reservoir can be used for the exploitation of these reservoirs in the country.