Day 2 Tue, March 14, 2023最新文献

{"title":"Reduced Polymer Loaded Fracturing Fluid For Extreme Temperature Proppant Fracturing","authors":"Prasad B. Karadkar, Ataur R. Malik, M. Alabdrabalnabi, Feng Liang","doi":"10.2118/214192-ms","DOIUrl":"https://doi.org/10.2118/214192-ms","url":null,"abstract":"\u0000 Guar gum and its derivatives based fracturing fluids are most commonly used in hydraulic fracturing. For high temperature wells, guar-based fracturing fluids need to be formulated with higher polymer loading and at high pH that leaves insoluble residue and tendency to form scales with divalent ions. In this paper, newly developed reduced polymer loaded fracturing fluids based acrylamide polymer was deployed from lab developments to field implementation. A thermally stable acrylamide-based polymer with a reduced polymer loading of 30-40% less than guar-based fracturing fluid was considered to minimize formation damage concerns. The crosslinked fracturing fluid viscosity was optimized at 340°F, bottomhole static temperature, and 315, 290, 265 and 240°F cooldown temperatures using a high pressure high temperature (HPHT) rheometer. For successful field deployment, a novel reduced polymer fracturing fluid was evaluated in the following sequence: chemical management, quality control, optimization of fracturing fluid formulations with field water, field mixing procedure, on-site QA/QC, data frac analysis and execution of main treatment.\u0000 This paper presents rheological studies of reduced polymer loaded fracturing fluids at bottom hole static temperature (BHST) and cool down temperatures of selected well candidates that demonstrate the superior thermal stability of this novel fracturing fluid. With a polymer loading of 35 lb/1000 gal, the fluid viscosity stayed above 300 cP at 100 1/s shear rate for 60 min at 340°F. The fracturing fluid formulations were optimized using both live and encapsulated breakers using high pressure and high temperature rheometer. Due to the fast hydration of the base polymer, the linear gel was mixed on-the-flying during the main fracturing treatment. The main fracturing treatment was successfully executed with a 40 barrels per minute (bbl/min) pumping rate with increased proppant concentration up to 4.5 pounds per gallon (ppa) using 40/70 HSP (high strength proppant) proppant. The fracturing fluid system based on the novel acrylamide copolymer offers advantages over guar-based fracturing fluid such as low polymer loading, excellent high temperature stability and less formation damage. This paper presents a systematic approach and lessons learnt during novel fracturing fluid deployment.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128573420","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Novel Approach to Identify Sand and Viscous Oil Problems Through the Analysis of Dynamometer Cards and Field Practices","authors":"K. Chanchlani, Deepak Gunwant, Ranjit Gogoi, Kamal Singh, Jeetendra Dadhich, H. Rajak","doi":"10.2118/214056-ms","DOIUrl":"https://doi.org/10.2118/214056-ms","url":null,"abstract":"\u0000 Problems due to the solids and viscous oil are difficult to predict in the dynamometer cards. An innovative approach is devised to identify solids and viscous oil problems, based on the interpretation of dynamometer card analysis and troubleshooting practices implemented at the field scale. Sand or wax incursion in the subsurface pump causes the pump screen or perforation to choke, resulting in no communication of the reservoir with the tubing. It can cause no free fall of polished rod and sucker rod string getting stuck up. Heavy viscous reservoir fluid shows the standing valve, traveling valve, or both pump seats getting choked. The drag force creates an extra differential force between the plunger and the pump, showing the case of the sucker rod unscrewing or parted as pump seats get choked up in the dynamometer card.\u0000 Casing head pressure, pump hydraulics, and the shape of the dynamometer card are critical parameters in differentiating between the fluid pound, gas interference, and blocked pump intake. The plunger stops before opening the traveling valve in case of pump intake is blocked, or the spiky and curvy loads in the dynamometer card due to solids-related problems. During the circulation job, higher pumping pressure taken by the pumping unit ascertains the solids incursion. Viscosity is an important property that determines load distribution on the rod string. The drag force causes the dynamometer card to stretch, but practically the rod is unscrewed or parted. Post-rod string makeup well started producing liquid. It has revived non-flowing wells and prevented production downtime. This unique approach will benefit the operators in analyzing the sand, solids, and viscosity-related problems and troubleshooting these failures of rod-pumped wells. Oil gain has been observed in rod-pumped wells based on this systematic approach.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"90 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129819932","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Anionic-Nonionic Surfactants for EOR in Carbonate Reservoirs","authors":"A. Scerbacova, A. Barifcani, C. Phan, A. Cheremisin","doi":"10.2118/214104-ms","DOIUrl":"https://doi.org/10.2118/214104-ms","url":null,"abstract":"\u0000 In this work, four linear alkyl ether carboxylates (AECs) C11E5A, C11E11A, C12E4A, and C12E7A were examined as agents for surfactant EOR. Their main properties that have a key effect on surfactants' performance during flooding were investigated: stability, interfacial tension (IFT), wetting ability, and spontaneous imbibition in limestone samples. The thermal stability and salinity tolerance was correlated with the molecular structure of AECs. IFT on the boundary with n-decane and crude oil was evaluated with the spinning drop tensiometry method at five temperatures in the range between 25°C and 70°C and various salinities. The wettability was studied through contact angle measurements of deionized water on the limestone plate surface. The core plates were aged in oil for 14 days to obtain the hydrophobic carbonate surface and then treated with surfactant compositions for 48 hours at 70°C. The wettability alteration mechanism was assessed through the Rock-Eval pyrolysis method, which was not previously applied for this purpose.\u0000 The experiments showed that ethylene oxide (EO) chain length influences the stability of AECs. It was found that the temperature rise substantially impacts a surfactant with a longer EO chain C11E11A. In contrast, brine salinity significantly affects the interfacial behavior of AEC with a shorter EO chain. C12E7A strongly hydrophilizes the surface, and the contact angle decreases from 110° to 15÷20°. The Rock-Eval pyrolysis analysis indicated that C12E7A has a better wetting ability due to a combination of \"cleaning\" (washing of hydrocarbons from the core sample surface) and \"coating\" (adsorption of surfactant molecules on cleaned spaces) mechanisms.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130445570","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Nimr Fields High Permeability Propped Fracturing Case Studies and Lessons Learnt","authors":"M. Al Kalbani, Ali Al Ghaithi, S. Al Kindi, Mehdi Mohamed Al Lawati, Ayman Ibrahim, A. Christiawan, R. Yuyan","doi":"10.2118/214143-ms","DOIUrl":"https://doi.org/10.2118/214143-ms","url":null,"abstract":"\u0000 Hydraulic fracturing in oil wells within the Southern parts of the Sultanate of Oman has been considered a niche application until recently. This is due to high formation permeability which is a key differentiator of oil fields in the South compared to the North where hydraulic fracturing is more prevalent in tight gas fields. Yet recently, hydraulic fracturing has gained momentum in the South as it started becoming a major well completion technique to increase production while decreasing drawdown. In addition to growing interest in injector well fracturing to enhance overall injector well pattern performance.\u0000 While hydraulic fracturing in high permeability formations has historically been attributed to damage bypass and creating a more conductive and a larger effective wellbore radius, it has been considered a risky endeavor in oil wells where post fracturing retained permeability may impair well potential especially in cases where oil is of moderate to high viscosity. Hence in Nimr fields, located Southern Oman, hydraulic fracturing of high permeability zones required a fit for purpose fracturing strategy that maintained good retained permeability at the targeted formation with minimal damage. This strategy included candidate selection using a pre-defined criterion derived from regression modelling, utilization of tip-screen-out designs, enhancing oxidizing breaker concentration for better cleanup and flowback, and optimal artificial lift pump designs to suit newly fracturing zones.\u0000 In Nimr, several poorly performing producers and injectors were treated in 2021 using hydraulic fracturing after being assessed against a rigorous selection criterion. These included several water injectors. Production and injection results were compared to the initially estimated Folds of Increase (FOI) prior to interventions. All wells achieved the expected estimated gain using a pressure matched fracture geometry estimate. Hence this method has provided a basis for further design optimization to increase production yield. Results have also provided lessons learnt in artificial lift pump sizing and pump seating depth. Injector wells were also assessed in respect to their patterns where results have shown significant pressure support to nearby wells, which in some cases revived wells that were previously shut in due to poor pressure support.\u0000 The success of hydraulic fracturing in high permeability wells in the South of Oman has driven the increase in frequency and magnitude of these otherwise niche interventions. Although further optimization in candidate selection and treatment designs are needed to ensure capital expenditure is justified by production gain.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116223646","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Practical and Economical Methodology of H2S Content Control in Mature Water Supported Field: A Case Study in Gulf of Suez, Egyp","authors":"Mohamed Abdulmageed Esmail, Tamer Hosny Abdelhalem, Islam Ibrahim Mohamed, Mohamed Hasan Elnahas, H. S. Mohamed, Mohamed Ahmed Yehia","doi":"10.2118/214282-ms","DOIUrl":"https://doi.org/10.2118/214282-ms","url":null,"abstract":"\u0000 Microbial hydrogen sulfide (H2S) production is a complication in the oil and gas industry. Production of H2S by bacteria within oil reservoir is detrimental to both injection and production. This study determines the root cause of the problem with a scientific approach to control H2S content – in a mature field in Gulf of Suez (GOS) – by applying different methods of chemical treatments in injectors, subsequently leading to production of fluids and gases with sustaining lower H2S content. The field depends on injection of sulfate-rich seawater into hydrocarbon containing reservoirs for pressure maintenance for 50 years. H2S content in the reservoir was relatively low before proceeding the water-flooding project. Initially, microbiological induced corrosion in oil production and water injection pipping were detected, then a strategy for monitoring the process of microbial production of H2S and its build-up within a reservoir and mitigation of induced scale by bacterial action was created. Finally, chemical injection approaches were implemented to reduce sulfate reducing bacteria (SRB) activity in the reservoir and to control / decrease H2S content in production fluids and gases.\u0000 Sharp increase in H2S content in production fluids and gases parallel with a decline in injection rate of water injection wells were the first signs of microbiological bacterial activity in piping and reservoir. In situ injection of biocide in production wells followed by soaking for 24 hours failed to decrease H2S content in production fluids. Continuous injection of oxygen scavenger with water stream in injection wells was the second trial that succeeded in decreasing H2S content in production wells, but only for short time, and then it increased yet again. This trial was the highest cost with low to moderate results. Last trial was to inject biocide with water stream in injection wells for three months, followed by H2S content observation in production wells. Chemical lab tests showed dramatic reduction of H2S content by 30 to 40% in some production wells in addition to tremendous improvement in injection rate of the injectors.\u0000 The case signifies the importance of root cause analysis and engineering problem solving techniques in finding a solution to reduce microbial hydrogen sulfide content caused by SRB action. Reduction of H2S allows opening of many shut-in producers that were producing high H2S content fluids and resulted in severe corrosion in addition to health, safety and environment (HSE) issues, particularly when assets were not designed to be operated in souring conditions.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116507617","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Thermal Degradation Kinetics of Synthetic Polymers in High-Performance Water-Based Muds for Designing Drilling Automation Processes for Viscosity and Fluid-Loss Control","authors":"D. Balaga, S. Kulkarni","doi":"10.2118/214134-ms","DOIUrl":"https://doi.org/10.2118/214134-ms","url":null,"abstract":"\u0000 For the purpose of engineering the drilling automation processes, it is necessary to explore the effects of thermal-degradation kinetics of synthetic polymers on the performance in different brine-based drilling muds in terms of time-dependent viscosity and fluid-loss control response. In this regard, three different synthetic acrylamide polymers with molecular weights between 2.8 to 3 million DU and sulfonation range between 15 to 40% are studied in sodium bromide (NaBr) brine based drilling mud systems.\u0000 To achieve the substitution during the polymerization process, the sodium salt of 2-acrylamido-2-methyl-1-propane-sulfonic acid was utilized as a sulfonated monomer. The substitutions were verified by NMR testings. The time dynamics of these synthetic polymers were quantitatively investigated using a simple and reliable titration technique in order to comprehend the degradation kinetics at various temperatures. Viscosity and fluid loss testings in drilling muds were contrasted with the polymer degradation which were hot rolled at 250°F and 350°F for various time durations. Viscosity and fluid loss were calculated for variously aged fluids with a conventional viscometer and API & HTHP filter presses.\u0000 The titration studies quantified the conversion of acrylamide molecules present in the polymer-chain into acrylic acid; the conversion represents the decay in polymer and was governed by the aging temperature and aging duration. The rate of polymer degradation decreased as the degree of sulfonation i.e., DoS in the polymer-chain increased, which was evident by a rise in Arrhenius activation energy. The drilling fluids which were hot rolled at 250°F showed a reasonable apparent viscosity in a range of 85 - 100 cp at room temperature and minimal HTHP fluid loss of 10 - 18 ml. Similarly, at 350°F hot rolling, all these fluids provided an apparent viscosity between 20 – 30 cp at room temperature with a HTHP fluid loss ranging from 36 – 42 ml. At both the temperature conditions, polymer with highest sulfonation provided a better control than other two polymers in terms of fluid loss and filter cake formation. These viscosity and fluid loss results were explained contradictorily with the effect of activation energy as sulfonation increased. In sodium bromide drilling muds, these results signified that higher sulfonation provides more thermal stability, but the polymer may be customized accordingly as per industry needs.\u0000 In order to maintain viscosity and fluid loss management, this research discusses how the polymer degradation kinetics affect the time-dependent performance of synthetic acrylamide polymers in brine-based drilling fluids at high temperatures. Usage of sodium bromide salt provided sustained increase in the base-brine density and also provided conductive environment for sulfonated acrylamide polymers. This is essential for creating drilling automation in terms of polymer replenishment for specific downhole temperature conditions.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128086874","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reservoir Rock Typing: Integration of Geological Attributes and Petrophysical Properties: Case Study from Yamama Reservoir","authors":"Maojun Qiu, Jiaju Yi","doi":"10.2118/214247-ms","DOIUrl":"https://doi.org/10.2118/214247-ms","url":null,"abstract":"\u0000 To build full-field static and dynamic models for supporting appraisal and development activities in F-Field in the southern part of Iraq, a comprehensive reservoir rock typing study for the Yamama carbonate reservoir was carried out by integrating geological information and petrophysical properties. This process involved first the integration of geological information (MICP, CT, thin section) to find the link between pore-throat sizes and petrographic information. The relationships were cross-checked by core descriptions with the depositional background information. After involving porosity and permeability from routine core analysis (RCAL), the rock types were identified and further grouped in the cross-plots. Because not all the plugs with permeability and porosity have MICP & thin section information, it was necessary to apply empirical rock typing methods, like rock fabrics number (RFN), flow zone indicator (FZI). Winland’s R35, to determine which method/classification could provide a better approach to classify the reservoir rock types (RRTs) with geological meanings based on core descriptions and petrographic description, which includes diagenetic overprints.\u0000 The FZI method shows a better match with Yamama reservoir Rock Typing. Sw-Height functions for each RRT were also created by using the Lamda method, and the parameters were tuned by wireline log-derived Sw. During the initialization of the dynamic model, the relative consistency of Sw distribution between static and dynamic models was reached. The relative permeability from special core analysis (SCAL) was assigned for each RRT. During the history matching process, a good pressure and production rate match was achieved.\u0000 This paper presents a RRT workflow for the typical matrix-based carbonate reservoirs with relatively limited core analysis data. By integrating the geological attributes and petrophysical properties, a better history match was achieved in the dynamic modelling, which could be used in forecasts and future reservoir management activities.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"115 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132731753","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Quantitative Assessment of CO2 Mineral Trapping Capacity in Presence of Sealing Fault in Carbonate Sequences: A Numerical Approach","authors":"A. Fathy, M. Arif, A. Adila, A. Raza, Mohamed Mahmoud","doi":"10.2118/213985-ms","DOIUrl":"https://doi.org/10.2118/213985-ms","url":null,"abstract":"\u0000 Mineral trapping is believed to be the safest and the most secure CO2 sequestration technique where the injected CO2 could be mineralized in the long-term (exceeding 102 - 103 years) geologically within subsurface formations. Nevertheless, the high complexity associated with CO2 mineral trapping capacity predications obscures the in-depth understanding of CO2 mineralization. In this study, a numerical simulation is adopted to demonstrate the impact of carbonate mineralogy in presence of a sealing fault on CO2 mineral trapping capacity.\u0000 Field-scale CO2 pilot topographic model for three distinct carbonate minerals is simulated to depict the mineral trapping capacity. Thus, realistic petrophysical parameters, reservoir characteristic curves, and other in-situ conditions are upscaled to mimic carbonate formations. Thereafter, the amount of CO2 mineralized is estimated for compositionally distinct reservoirs. Additionally, the effect of injection pressure on CO2 mineralization is assessed upon precipitation/dissolution kinetics calculations. Moreover, the effects of well placement and perforation depth on mineral trapping potential of calcite, dolomite, and siderite dominant reservoirs are assessed.\u0000 The mineral trapping capacities computed show that increasing injection pressure (base injection pressure to 1.5*base injection pressure) monotonically increased the mineral trapping capacities for calcite and dolomite. However, siderite seems slightly insensitive to the injection pressure increase. This monotonic trend is attributed to enhanced radial displacement and restricted plume migration upward as the injection pressure increases. Moreover, proper CO2 injector placement showed significant enhancement in mineral trapping capacity especially if the injector is near to the fault plane on the leaking side. This study provides in-depth theoretical understanding of the mineralogy effect on CO2 mineralization potential in faulty carbonate sequences. This is driven by the insignificance interest mineral trapping has gained over the years compared to other trapping mechanisms. This is because of the extremely long storage duration needed for mineral trapping to reach its maximum potential. Importantly, the results suggest that CO2 mineralization within carbonate reservoirs immobilize CO2 – thus assisting in stable and long-term permanent storage.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"66 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133932030","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Acoustic Velocity of Carbonate Rocks and the Effect of Cracks on Velocity","authors":"Jianming Chen, Haiyang Zhang, M. Arif, Yunzhong Tu, Jiasheng Zhang, Xiaosai Wang, S. Nizamuddin","doi":"10.2118/214096-ms","DOIUrl":"https://doi.org/10.2118/214096-ms","url":null,"abstract":"\u0000 The acoustic velocity is very closely related to rock properties such as porosity, permeability etc. These relationships are particularly important for carbonate rocks. It is thus vital to examine the interpretation of acoustic velocity as a function of rock properties. The primary goal of this study was to examine how rock properties e.g., porosity, permeability and crack density, affect the acoustic velocity of rock samples. For this purpose, 24 carbonate plug samples from Ras Al-Khaimah were examined. The recrystallized carbonates depicted a very low porosity and a significant amount of fractures were examined. A unified theory for elastic wave propagation through porous media containing cracks was used for the quantitative description of cracks and the relationship between cracks and acoustic velocity was also investigated. A positive correlation was found between the P-wave velocity difference and the corresponding inverted crack density difference. The results of this study provide new insights into the acoustic behavior of carbonate rocks.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133102928","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of Over-Pressured Gas Reservoirs: Reserves Estimation to Production Performance - A Case Study","authors":"Iqbal Muneez, Mehmood Saad, Hasnain Muhammad, Munawar Qazi, Zafar Jahangeer","doi":"10.2118/214141-ms","DOIUrl":"https://doi.org/10.2118/214141-ms","url":null,"abstract":"\u0000 Geo-pressured reservoirs are challenging in terms of in-place estimation and maintaining sustained production. Estimation of Gas Initially In-place (GIIP) using P/z from early data shows incorrect estimation and resulted in over-predicting GIIP. Typically, over-pressure gas reservoirs show downward curvature in P/z plot early or slightly delayed depending upon the pool limit and the degree of overpressure. A rapid decline in production also observed in the over-pressured gas reservoirs resulted in low hydrocarbon recoveries. This paper aims for correct GIIP estimation in over pressured gas reservoirs and to better manage and maximize recoveries from the Field.\u0000 Based on available pressure and production data, two approaches were used in order to estimate the GIIP of the Field. (1) Conventional P/z by using Hammerlindl method (2) Developed analytical model by incorporating rock compressibility value from the Geomechanical SCAL study. The calculation of GIIP from both the methods are somewhat in close agreement as the vital factor of rock compressibility was introduced in GIIP estimation, to cater for the effect of reducing porosity as the pressure drops, resulting in changing storage capacity of the rock. Additionally, consecutive pressure Build-up data history showed reduction in permeability with the time from 9 mD to 0.4 mD. This change in permeability is caused by near wellbore overburden stress increase resulting in rock expansion which in turn reduces/closes pore throats. This manifest as an apparently damaged region causing lower rates and poor recoveries. In this scenario the well would be shut-in at higher abandonment conditions.\u0000 Basic geo-mechanical parameter of rock compressibility plays an important role in reserves estimation for over-pressured reservoirs. Previous literature and our evaluation suggest that optimum production strategies for such reservoirs are: (1) To produce at lower rates at which drawdown is less than half of prevailing pore pressures. (2) Drill more wells to sustained production while producing at lower rates. Both strategies under optimum conditions would result in uniform depletion and better recoveries.\u0000 Production performance with time, rapidly decreases as permeabilities reduce due to near wellbore stress sensitive region caused by larger drawdown so a controlled drawdown is recommended.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133684840","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}