Fracture Characterization and In-Situ Stress Analysis in Tight Carbonates of Potwar Basin, Pakistan

Evaluating natural fractures in tight carbonate reservoirs during the exploration and early development stages is critical in order to reduce geological uncertainty and determine well trajectory in future horizontal drilling. Challenges are often found in both acquiring the adequate data and assessment of the fractures/sub-seismic faults in the oil based mud borehole environment. This paper summarizes part of the experience learned from the use of an optimal dataset in addition to a workflow on fracture characterization for tight deep carbonate reservoirs in Kuwait. In the process of exploration and development of these particular reservoirs, oil-based mud has been used in the drilling process due to the concerns of wellbore stability. Acoustic images and core was acquired in the early stages of the field development. After the invention of a micro-resistivity imaging tool it was used in combination with the acoustic imaging for integrated and enhanced formation evaluation, which allowed reduced coring for a cost saving. The paper explains the advantages and limitations of each image dataset and describes how the acoustic and micro-resistivity images are complementary to each other. The paper also presents how different datasets gives partial contribution to the overall geological understanding of the field. More importantly, the case study shows that the combination of both image data sets provides a much better and more complete picture of fractures in the wellbore with limited core calibration. Smaller scale faults, which are usually not detected or poorly imaged on seismic, can be interpreted on images with definition of vertical displacement through the integration of well correlation and cross sections. The output from this study provides an essential database for well completion decision, fracture reservoir modeling, infill drilling plan and future horizontal well placement.

Performance Evaluation Of Horizontal Wells In A Tight Carbonate Reservoir. Abstract This paper presents a case study of evaluation of the performance of horizontal wells drilled in a tight carbonate reservoir in Kuwait. Successful wells were those that intercepted natural fractures. A methodology was developed to define the reasons for the performance of horizontal wells. The methodology involved use of geological, petrophysical geochemical, transient test, rock, and fluid properties to develop a numeric simulation model. Conclusions regarding well performance were made by using a newly developed analytic simulator and the numeric model. While the analytic simulator provided rapid rate forecasts, the numeric simulator gave insight into the causes for unsatisfactory well performance. For example. well placements within the bed, low-permeability rock, and unfavorable relative permeability characteristics all contribute to the rapid rate decline and the associated increasing gas/oil ratio (GOR) production. We developed cyclical production and oil injection schemes to address the high-GOR production problems. In the first scheme, a well is produced and shut-in alternatively to preserve the reservoir energy, and in the second, oil is injected periodically to minimize the gas saturation. Both methods increase the ultimate oil recovery. Introduction Horizontal well technology has evolved rapidly since pioneering drilling efforts were begun in late 1970s in the Raspo Mare Field offshore Italy. In the US, spawned by successes at the Austin Chalk formation in East Texas since 1985, the horizontal drilling activity gained considerable momentum. Austin Chalk happens to be a tight carbonate with extensive vertical and sub-vertical fracturing. Despite publication of numerous successful case histories, Beliveau, while compiling a major operator's world-wide horizontal well efforts, observed that many-fold production increases do not often materialize because of incomplete knowledge of reservoir heterogeneity before drilling. North Sea's Ness field is also a case in point. Combined industry experiences suggest that the success of horizontal wells lie in selecting the right candidate reservoir. Fayers et al. summarizes some of the reservoir engineering issues that need considering while evaluating horizontal well prospects. Besides gaining productivity increases in general, horizontal wells have enjoyed success in combating coning or cresting of water and/or gas, in accessing by-passed oil and multiple flow units, and in converting resource into reserves, such as those in heavy oil and tight reservoirs. Examples of high-permeability sandstone reservoirs where water coning has been mitigated include Troll field in the North Sea, Prudhoe Bay field in Alaska, Safaniya field in the Middle East, and those in offshore west Australia. Similarly, horizontal wells in Rospo Mare, the Karsted limestone reservoir, have enjoyed considerable success in mitigating water coning. While horizontal well successes are often presented in various forums, the associated failures do not gain as much publicity. Generally speaking occurrences of failure are high with carbonate reservoirs where successes depend largely upon horizontal wells intercepting natural fractures. South Kuwait's Mauddud reservoir in discussion is a low-permeability carbonate with sparse fracture development. Successful exploitation of reserves with horizontal wells in similar reservoirs has not been reported. Only the Dan field in the North Sea and the Kharaib B reservoir offshore Qatar have permeabilities that are comparable to this reservoir; that is, 1 to 10 md. However, they are much thicker and lend themselves to hydraulic fracturing because of confining shale barriers. Besides accessing fractures, the fluid-rock interaction with changing fluid saturations plays a critical role in the success of long-term producibility potential of a well. Thus, initial screening criteria should encompass this aspect before drilling horizontal wells. P. 601

This paper presents a case study of evaluation of the performance of horizontal wells drilled in a tight carbonate reservoir in Kuwait. Successful wells were those that intercepted natural fractures. A methodology was developed to define the reasons for the performance of horizontal wells. The methodology involved use of geological, petrophysical geochemical, transient test, rock, and fluid properties to develop a numeric simulation model. Conclusions regarding well performance were made by using a newly developed analytic simulator and the numeric model. While the analytic simulator provided rapid rate forecasts, the numeric simulator gave insights into the causes for unsatisfactory well performance. For example, well placements within the bed, low-permeability rock, and unfavorable relative permeability characteristics all contribute to the rapid rate decline and the associated increasing gas/oil ratio (GOR) production. We proposed cyclical production and oil injection-production schemes to address the high-GOR production problems. In the first scheme, a well is produced and shut-in in an alternating fashion to preserve the reservoir energy. Oil is injected for a very short duration to alleviate the near-wellbore gas saturation problem in the second scheme. In both cases, the high-GOR production is minimized and the ultimate oil recovery is improved. Introduction Horizontal well technology has evolved rapidly since pioneering drilling efforts were begun in late 1970's in the Raspo Mare Field offshore Italy. In the US, spawned by successes at the Austin Chalk formation in East Texas since 1985, the horizontal drilling activity gained considerable momentum. Austin Chalk 1 happens to be a tight carbonate with extensive vertical and sub-vertical fracturing. Despite publication of numerous successful case histories, Beliveau, while compiling a major operator's world-wide horizontal well efforts, observed that many-fold production increases do not often materialize because of incomplete knowledge of reservoir heterogeneity before drilling. North Sea's Ness field is also a case in point. Combined industry experiences suggest that the success of horizontal wells lie in selecting the right candidate reservoir. Fayers et al. summarize some of the reservoir engineering issues that need considering while evaluating horizontal well prospects. Besides gaining productivity increases in general, horizontal wells have enjoyed successes in combating coning or cresting of water and/or gas, in accessing by-passed oil and multiple flow units, and in converting resource into reserves, such as those in heavy oils and tight reservoirs. Examples of high-permeability sandstone reservoirs where water coning has been mitigated include Troll field in the North Sea, Prudhoe Bay field in Alaska, Safaniya field in the Middle East, and those in offshore west Australia. Similarly, horizontal wells in Rospo Mare, the Karsted limestone reservoir, have enjoyed considerable success in mitigating water coning. While horizontal well successes are often presented in various forums, the associated failures do not gain as much publicity. Generally speaking, occurrences of failure are high with carbonate reservoirs where successes depend largely upon horizontal wells intercepting natural fractures. South Kuwait's Mauddud reservoir in discussion is a low-permeability carbonate with sparse fracture development. Successful exploitation of reserves with horizontal wells in similar reservoirs has not been reported. Only the Dan field in the North Sea and the Kharaib B reservoir offshore Qatar have permeabilities that are comparable to this reservoir; that is, 1 to 10 md. However, they are much thicker and lend themselves to hydraulic fracturing because of confining shale barriers. Besides accessing fractures, the fluid-rock interaction with changing fluid saturations plays a critical role in the success of long-term producibility potential of a well. P. 643^

Tight oil reservoirs are widespread around the world and are unconventional due to their low permeability and typical composition of shale. The traditional technique of exploring these reservoirs is usually hydraulic fracturing, which has not had much success in carbonate reservoirs in Iraq. This study aims to provide an appraisal of a new method to improve oil recovery in these challenging formations, offering a detailed evaluation of its effectiveness compared to traditional stimulation techniques. We analysed and compared horizontal well, fishbone stimulation, multi-stage hydraulic fracturing, and our new proposed approach, which we call Fishbone Hydraulic Fracturing Stimulation (FHFS), using numerical reservoir simulation software. The dynamic reservoir model was constructed using real data from an Iraqi field, with a multilateral technique and local grid refinement (LGR) to simulate a single fishbone well followed by hydraulic fracturing in open-hole completion. Multiple scenarios were considered in the evaluation of the potential for this method to enhance oil recovery compared to traditional stimulation methods. Additionally, sensitivity analysis was performed on different reservoir parameters. Simulation results of a six-year period of production indicate that the FHFS technique significantly enhances cumulative oil production in a tight carbonate reservoir (the Sadi formation) compared to alternative stimulation techniques. An increment cumulative oil production of 45-50% was achieved with FHFS compared to standard Fishbone stimulation. The result was 2,8003,000% higher than a conventional horizontal well. These results are based on the FHFS enhanced of permeability from 0.65 md to 165 md for the Sadi formation. To evaluate the durability of the analysis, the fracture induced permeability improvement was adjusted to 100 md given that permeability is a critical factor in tight reservoirs. Under this condition, FHFS yielded approximately 30 % higher cumulative oil production compared to standard Fishbone Jetting Stimulation. When the permeability enhancement was reduced to 75 md, FHFS still outperformed Fishbone, but with a reduced improvement of about 20% in cumulative oil production. However, at 40 md, fishbone outperformed the FHFS, while at 45 md, both methods yield equivalent results. Therefore, given the inherent uncertainty of future oil prices, it is imperative to develop and adopt highly productive, pre-emptive techniques for tight reservoirs, which may be feasible to maximise production. The most significant finding is that FHFS significantly enhances recovery in tight formations. This is critical because higher recovery rates directly impact the economic viability of tight reservoirs. This study presents a novel systematic evaluation of FHFS, an emerging but underexplored stimulation technology. By integrating the benefit from the unique geometry of fishbone wells with traditional hydraulic fracturing, this approach offers a 45% improvement in cumulative oil production compared to existing techniques. The findings provide insights for engineers on the potential of FHFS as an innovative and highly effective stimulation method for tight carbonate reservoirs, particularly valuable during periods of high oil prices.

Report reviews the application of modern phenomenological and holistic models as well as innovative horizontal drilling technologies and interpretation 3D seismic to improve oil recovery of tight oil carbonate reservoirs. The new scientific model and an integrated approach in the development of unconventional carbonate reservoirs with low porosity. The systems was first implemented during the drilling of two horizontal wells in USA with the close cooperation of Russian, American and Australian experts. The concept of the model is aimed to identify high permeability fracture zones before drilling of the wells, their optimal crossing by the open horizontal hole and preservation in the process of drilling the primary of permeability of fractures, created by the nature itself, which can be considered as an alternative to multistage fracturing and other technologies which are commonly use in the development of hydrocarbons in tight oil and gas reservoirs. Received in the process of joint work results have been planning to be used not only to drill new wells to tight carbonate reservoirs and shales in South Texas, but also in similar fields in tight reservoirs in Western and Eastern Siberia, Timan-Pechora and Volga-Urals oil and gas basins in Russia as well as abroad.

The tight oil reservoir has low porosity and permeability, and generally suffers from rapid declines in production rates for oil wells, especially in southeast Iraq in the Halfaya oil field of the Sadi Formation, which is considered a tight oil reservoir with a reserve of about 25%; their OOIP accounts for more than a quarter of the total in the H oilfield. Implementing a pilot hydraulic fracture technique was a focus of attention in Iraq to increase the production rates, but the main issue faced in hydraulic fracturing wells was producing a high oil rate for a short period of time and then starting to decline rapidly, so a reservoir dynamic model was utilized to achieve the purpose of this study. The purpose of this study is to predict the production rate to prolong the production stabilization in horizontal and vertical hydraulic fracturing wells in order to avoid highly depleted fracture storage capacity and production below the bubble point. Recognize a practical procedure with horizontal hydraulic fracturing wells to reach stabilization. The reservoir simulator results show that a good history matches till 2021, predicting the rates that stabilize the production with flowing pressure above the bubble point pressure till 2025, producing rates for an eight-stage well with 700 BOPD and 900 BOPD for an eleven-stage well, whereas the rate for a vertical hydraulic fracture well is 225 BOPD. A practical procedure in horizontal hydraulic fracturing wells is achieved by keeping the wellhead pressure constant during the production period to stabilize transient behavior.

Unconventional reservoirs bear a unique perplexity in that, at every scale, they are different from their conventional counterparts and even one another. Small nuances in any one parameter can result in a vastly different well result, which may affect how an area, or even an entire play, is interpreted. This month’s selection of papers is all about those differences, in recognition that it is technology that drives innovation through understanding what these differences mean and how best to extract value from these vast resources. Starting at the well scale and looking at the benefits of knowing the efficacy of each stimulation stage, paper URTeC 3864145 is from the Ordos Basin in China. Investigating hydraulic fracture performance on a stage-by-stage basis proves time and time again that understanding the details can improve overall development outcomes. The case study reviews two hydraulic fracture diagnostic techniques used in combination to determine water breakthrough and shutoff plans. Zooming out to the play scale, paper SPE 216292 is focused on the most variable of unconventional reservoirs: the carbonate reservoir. This case study of the Austin Chalk formation in Texas analyses the production uplift from application of horizontal, multistage fracture stimulation technology in tight or fractured carbonate reservoirs. The application of unconventional technology in carbonate reservoirs can extended field life, and the deployment of this technology should be considered for any redevelopment or reassessment of potential resources trapped in tight carbonate reservoirs. Finally, paper OTC 34832 draws on the concept of innovation that is required to unlock unconventional resources. Novel methods of stimulation are the cornerstone of unconventional technology in that well stimulation is a basic requirement of all low-permeability reservoirs. The paper describes a trial pilot from idea through execution from Kuwait Oil Company for enhanced oil recovery in tight formations using downhole hydrogen generation from in-situ exothermic multistage chemical reactions between two unique hydroreacting agents. The paper also provides lessons learned and optimization insights from the trial, concluding that a successful, low-cost alternative stimulation technique was demonstrated and repeatable. Recommended additional reading at OnePetro: www.onepetro.org. SPE 216139 Tight Gas Reservoir Characterization and Comparison of PLT Methods: Microseismic Monitoring, Fiber-Optical Production Logging, and Tracer-Coated Sand Monitoring Applied in the Same Well by Xiao Yao, Petrochina, et al. SPE 216149 New Insight in Developing Tight Fractured Carbonate Reservoirs, Mishrif Formation, West Kuwait by M. El-Jeaan, Kuwait Oil Company, et al. SPE 215712 Successful Utilization of In-Situ Dune Sands in Saudi Arabian Unconventional Frac Operations by Nahar Qahtani, Saudi Aramco, et al.

ABSTRACT: The development of deep and tight carbonate reservoirs is essential due to their widespread distribution and significant hydrocarbon accumulation. Acid fracturing is commonly employed to stimulate wells in these reservoirs, offering advantages such as ease of application and avoiding screen-out issue compared to proppant fracturing. However, acid fracturing may face challenges in maintaining effective fracture conductivity, particularly under high in-situ stress conditions typical of deep and tight reservoirs. Relying solely on acid fracturing can potentially lead to reduced oil and gas production. To address this challenge, we propose an integrated workflow for optimizing stimulation in deep and tight carbonate reservoirs. This workflow assists in selecting the appropriate fracturing method by incorporating several key components: carbonate rock typing, calculation of the breakdown pressure envelope and optimal perforation direction, estimation of acid fracture conductivity, identification of ideal perforation locations, and determination of fracturing methods (acid or proppant fracturing). To evaluate acid fracture conductivity and its potential decline, we introduce two new parameters: the acid fracture conductivity threshold (AFCT) and the fracture conductivity declining index (FCDI). These parameters, which can be derived from log data, 1D Mechanical Earth Model (MEM), and laboratory tests, help assess the performance of acid fracturing. The AFCT measures the effectiveness of acid fracturing, while the FCDI accounts for the impact of in-situ stress and rock compressive strength on fracture conductivity. The workflow recommends using acid fracturing when the AFCT is high and the FCDI is low, indicating favorable conditions for acid treatment. Conversely, it suggests proppant fracturing when the AFCT is low or the FCDI is high. An example study demonstrates the application of this workflow to select the appropriate fracturing method for wells in deep and tight carbonate reservoirs. By analyzing log data to identify optimal rock types and perforation locations, the workflow provides guidance on whether acid or proppant fracturing should be employed. Overall, proppant fracturing seems to be a better choice for deep and tight carbonate reservoirs compared to acid fracturing.

Characterization of seismic anisotropy using azimuthal AVO analysis (AVAz) - An application case study in the deep and tight carbonate reservoirs from Potwar Basin onshore Pakistan

The developement of carbonate reservoirs through horizontal wells is difficult task that requires the incorporation of geomechanical, geological, petrophysical and engineering parameters. Classical approaches tend to define the target zones with high hydrocarbon potential, and adjust the well landing zone while drilling. Those approaches had shown their limitations especially when dealing with injecting in tight carbonates reservoirs. In fact, the drilling engineer needs to take into account the intrinsic pore geometries and capillary forces that govern the water flooding mechanism in carbonates reservoirs, and the mechanical characteristics of the rocks, in order to optimize the drilling parameters. The paper presents a workflow that integrates the uncertainty in the modeling of the geomechanical characteristics of the rocks and an objective function that is associated with the geomechanical characteristics. We will focus on the Formation Parting Pressure (FPP) as several studies showed that the FPP is a critical geomechanical parameter for the drilling of horizontal injector wells in the tight carbonate reservoirs.

Development of a tight reservoir characterized by low permeability poses significant challenges to the oil and gas industry due to the low productivity and the excessive costs. This study explores the potential of utilizing "Fishbone Wells" compared to multi-fractured horizontal wells to maximize the net present value (NPV). The development approach is assessed for implementation in a tight carbonate reservoir in southern Iraq. Numerical reservoir simulation models were utilized to predict oil production rates and optimize key parameters such as the number of branches for the fishbone well. Analytical models were used to calculate behaviour for both types of wells then, the outcomes were compared. Our findings indicate that both multi-fractured horizontal wells and fishbone wells can achieve a positive Net Present Value (NPV) in the Sadi reservoir. However, the fishbone well consistently delivers higher NPV under specific conditions. Fishbone wells utilize smaller lateral branches, known as 'subs,' each containing 3 or 4 needles (or ribs) with a diameter of half an inch and 40 ft length. These needles usually have a 70% success rate in reservoir penetration. The well design limits each stage to12 subs because of the 40-foot spacing between subs and the 480-foot distance between hydraulic fracturing stages. Although 12 subs yield the highest production, our analysis found that a configuration with six subs optimizes NPV compared to one stage of hydraulic fracturing. It is important to note that the fishbone technology is most effective in reservoirs with permeability of 0.5 millidarcy or higher. In formations with lower permeability, hydraulic fracturing, which can be implemented below 0.5 millidarcy, may be the more reliable approach. While fishbone wells offer significant profitability potential, they also come with marginal risks and require favourable reservoir conditions to ensure success. As such, careful reservoir assessment is critical before selecting this technology for development. This is the first study that compares the economic feasibility of fishbone stimulation technology to the multi-fractured horizontal wells implemented in a real case for tight reservoir formation.

Summary Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.

The State of Kuwait is currently appraising and successfully developing the tight carbonates reservoirs of Jurassic age, which have very low matrix porosity and permeability. These reservoirs are affected by several tectonic events of faulting and folding, resulting in the development of interconnected natural fractures, which provide effective permeability to the reservoirs in form of production sweet spots. The objective of the study was to characterize the natural fractures and identify high permeability sweet spots as being appraisal drilling locations in a discovered field with tight carbonate reservoirs. An integrated approach was undertaken for building a discrete fracture network model by characterizing the developed faulting- and folding-related fractures and combining all subsurface data from multiple domains. The reservoir structure has a doubly plunging anticline at the field level that is affected by several strike-slip faults. The faulting-related fractures were characterized by generating multiple structural seismic attributes, highlighting subsurface discontinuities and fracture corridors. The folding-related fractures were modelled using structural restoration techniques by computing stresses resulting from the anticlinal folding. The fracture model was built in addition to the 3D matrix property model for this tight carbonate reservoir, resulting in a dual-porosity-permeability static model. Analogue data was used to compute fracture aperture and expected fracture porosity and permeability, to identify the sweet spots. Structural seismic attributes such as Ant Tracking and Consistent Dip were successful in highlighting and identifying the fault lineaments and fracture corridors. The seismic discontinuities were validated using the fractures interpreted in the image log data from the predrilled wells before being input into the fracture model. Paleo stresses, derived from structural restoration, were combined with the reservoir facies and geomechanical properties to gain important insight into predicting fractures developed due to folding. Several fracture aperture scenarios were run to capture the uncertainty associated with the computed fracture porosity and permeability. Based on the results, several sweet spots were identified, which were ranked based on their extent and connected volumes of the various permeability cases. Identifying these sweet spots helped make informed decisions regarding well planning and drilling sequence. High-inclination wells aligned parallel to the present-day maximum stress direction were proposed, which would cut across corridors of the predicted open fractures. Through this study, comprehensive fracture characterization and fracture permeability understanding of the tight carbonates in the field under study were successfully achieved. This workflow will be useful in exploratory or appraisal fields with tight carbonate reservoirs.

ABSTRACT: Acid fracturing is commonly used in tight carbonate reservoirs to increase production. The efficiency of acid fracturing is greatly influenced by the type of acid systems. With the development of carbonate reservoirs towards ultra-deep and ultra-high temperatures, the acid system faces greater challenges. In this paper, the temperature resistance, retardation, and conductivity of the new cross-linking acid were evaluated by rotating disk instrument, Haake Mars III rheometer, and FCS-842 conductivity meter, respectively. The results show that the viscosity of the cross-linked acid system is stable at 80 mPa.s in the temperature range of 120°C to 140°C, the acid-rock reaction rate is half lower than that of similar cross-linked acids, and it has good temperature resistance and retardation characteristics. The acid etching and conductivity experiments show that the new cross-linked acid etched rock slab to form channels with high initial conductivity, which is a good choice for acid fracturing in high temperature and deep carbonate reservoirs. 1. INTRODUCTION According to HIS statistics, carbonate oil and gas resources account for about 70% of the global oil and gas resources, and about 60% of the world’s total oil and gas production comes from carbonate oil and gas reservoirs (Li et al., 2018). Chinese marine carbonate rocks are characterized by wide distribution, old age, deep reservoir depth, and high temperature. Deep carbonate reservoirs have low permeability and complicated pore structures. It generally composed of dissolved caves, fractures and dissolved pores with substantial heterogeneity (Zhao et al., 2008; Zhang et al., 2020). Low-permeability and tight carbonate reservoirs have no natural production capacity or low natural production capacity and require stimulation measures such as acidizing or acid fracturing. Acidification means that the acid solution is injected into the formation below the fracture pressure of the formation. And the acid solution dissolves the rock to form wormholes, penetrates the pollution zone, and restores the formation permeability. Acidification is generally used in low-permeability carbonate reservoirs with polluted near-well-bore area, where the stimulation scale is small and the stimulation distance is limited (Mateus P. S. et al., 2020). Acid fracturing is similar to hydraulic fracturing in the stage of fracture generation (Yue et al., 2021), which uses high-viscosity fluid to open up the reservoir. Then, the acid fluid reacts with the rock, dissolves part of the rock, and makes the fracture surface non-uniform. Different from hydraulic fracturing (A. Suleimenova et al., 2016), acid fracturing does not use proppant. After the operation, the fracture props itself open with the relatively undissolved regions acting as proppants, and provides channels for oil and gas flow shown in Fig. 1. In order to obtain good performance, large scale of acid fracturing is generally used in tight carbonate reservoirs stimulation.

Hydraulic fracturing can be utilized to extract trapped hydrocarbon where integrated fracture networks do not exist for sufficient production. In this work, design parameters of a hydraulic acid fracturing of a tight carbonate reservoir in the Middle East were optimized. The effect of optimized hydraulic fracturing on production performance and rate was investigated. Using the petrophysical well logs, formation integrity tests, core data the Mechanical Earth Model (MEM) of the tight carbonate reservoir was created, which resulted in rock mechanical properties and in-situ stresses. The other required parameters for fracturing design were either measured or found from empirical correlations. Following a candidate selection of suitable layers for fracturing, the input parameters were loaded in GOHFER software to design and optimize the fracturing job. Finally, the production forecast was performed and compared with current conditions. The injection parameters (flow rate, total volume, and number of stages) of the fracturing fluid (composed of guar and CMHPG and polymer with 15% HCL acid) were optimized to reach optimum resultant fracture geometry. Finally, optimized injection parameters were found at the injection flow rate of 18 barrels per minute, total injection volume of 90 K-gal, and three stages of injection. Using the optimal injection parameters, the optimized fracture geometrical sizes were determined: the fracture half-length (Lf): 148 m (486 ft), fracture height (Hf) of 64 m (210 ft) and fracture width (Wf) of 0.0962 in. Finally, the effect of this stimulation method on future production performance was investigated. The well production rate showed an increase from 840 STB/Day (before fracturing) to 1270 STB/Day (post fracturing). This study contributes to the practical design and optimization of hydraulic fracturing in the tight carbonate formation of the investigated oilfield and the other potential fields in the region. The results showed that this stimulation method can efficiently improve production performance from reservoir formation.