Day 1 Mon, March 21, 2022最新文献

{"title":"Reassessing Artificial Lift Selection in a Challenging Thermal Field","authors":"A. Alwazeer, Khadija Shaqsi, Amur Habsi, A. Busaidi, Khalid Salhi, M. Balushi, A. Hinai, Hamood Husaini, P. Putra, A. Hilali, R. Mujaini","doi":"10.2118/200193-ms","DOIUrl":"https://doi.org/10.2118/200193-ms","url":null,"abstract":"\u0000 This paper reviews the process for artificial lift selection and highlights the creativity applied to solve operational challenges. Artificial Lift (AL) systems are an essential component of oil and gas production in which wells are not flowing naturally to surface. The typical factors in assessing AL selection in conventional fields are driven by cost, anticipated rates, operating envelopes, depth and also factors such as corrosive elements, sand expectation, anticipated failure rates and operational experience. However, in heavy oil fields, the selection is complicated by additional factors such as Steam Break Through (SBT) and extreme viscosity variation. Many challenges were encountered during the actual operation of \"A\" East field which required revisiting early assumptions and modifying both lift selection and operating philosophy.\u0000 The \"A\" East reservoir has an oil viscosity range between 400 to 400,000 cp at reservoir conditions. In order to deplete the high pressure in the reservoir (~137 bar) and minimize the adverse impact on steam injection quality and efficiency, about 40% of the wells were selected to be cold produced, initially using Progressive Cavity Pumps (PCP) to handle higher viscosities. These selected cold producers would later be converted to Cyclic Steam Stimulation (CSS) using Beam Pumps (BP). Cold production helped to lower the reservoir pressure. The remaining of the field operated with BP using down hole Steam By Pass Pumps (SBPP). The SBPP approach was adopted to minimize conversion time between injector and producer in CSS cycles.\u0000 Challenges operating the SBPP pumps led to abandoning this approach, however, the insert pump concept continued. There were notable challenges operating the insert pumps as well mostly at the flanks after several steam cycles and various efforts which required a re-evaluation of AL systems available. Metal to Metal Progressive Cavity Pump (M2MPCP) was introduced to mitigate some extreme viscosities encountered in the flanks and reaching viscosities above 15000 cp at 60 C° (see figure 1).\u0000 There were some operating challenges related to slow optimization and reaction times were mitigated by the introduction of automation using an algorithm-driven approach. Other challenges were related to BP start-ups in thick oil and other pump struggles with gas locking due to SBT. These challenges required adaptations and modifications such as slow start after interventions until heated fluids arrive to the wellbore. In other cases, production choke backs allowing for single phase flow through the pump. Conversion methods between cycles was accelerated by the introduction of stripping tool. Optimization efforts were also challenging and slow and demanded higher than expected manpower, this challenge was addressed by utilizing automation and algorithms which made a significant difference.\u0000 The selection of a suitable AL system needs to take into consideration the overall requirements at the different de","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78588689","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":"A Comparative Analysis for Optimal Fracture Design Between the Crest and Flank Wells. Examples from Saih Rawl, Oman Tight Gas Field","authors":"A. A. Al Hinai, M. Abdelazim, Khalfan Mubarak Al Bahri, Ahmed Abdullah Al Suleimani, A. Nunez, Aadil Salim Al Shekaili","doi":"10.2118/200038-ms","DOIUrl":"https://doi.org/10.2118/200038-ms","url":null,"abstract":"\u0000 Saih Rawl gas is located in the South Oman Salt Basin. There are two main formations targeted for gas production; Barik & Miqrat Formations. These formations are tight and exhibit low permeability. In order to enhance gas production, these formations have to be hydraulically stimulated.\u0000 The main objectives of this paper is to demonstrate the petrophysical properties of the hydraulically fractured zones. Assess gas flow contribution thru the individual zones measured by production logging and comparing with the amount of proppant placed in the formation. In addition, the paper discusses reservoir properties and characteristics obtained from logging, post stimulation operations results and post stimulation gas production. The paper discusses 20 wells; 10 from the crest and 10 from the flank. The two formations Barik and Miqrat cover approximately 17 sub reservoir units.\u0000 The total overall placement ratio is 95% and 78% for the crest and flank respectively with 156 hydraulic stimulation stages. It was observed that five sub reservoir units proved to be challenging to place the desired proppant. The maximum operating pressure is reached before achieving the desired proppant concentration leading to a screen out; concentrations of 2 – 3 pounds per gallon. Petrophysical evaluation of porosity and permeability cross plots showed a linear relationship in the wells in the crest. While there was no clear relationship was seen in the flank. Radioactive tracers used are to understand if there is any proppant propergation into the higher or lower zones. Not all the five challenging sub reservoir units showed propergation to other units. The wells located in the crest showed a better production rate as compared to the flank.\u0000 The paper highlights the importance of the using petrophysical evaluation to optimize hydraulic fracturing design for successful operations.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"383 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86686194","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":"Optimizing the Performance of Produced Water Chemical Treatment Following CEOR Polymer Breakthrough","authors":"M. Hesampour, S. Toivonen, Saija Holpoainen, Jouni Koski, Prince Sheril, Iris Porat, L. Bava","doi":"10.2118/200292-ms","DOIUrl":"https://doi.org/10.2118/200292-ms","url":null,"abstract":"\u0000 Chemical enhanced oil recovery (CEOR) plays a major role in sustaining production, extending the life of field and improves the recoverable reserves which is of economic benefit. The injected polymer will eventually propagate to the production wells where it is co-produced with production fluids. The presence of polymer in the back produced water may increase the residual oil levels and suspended solids in the produced water. This causes production systems bottlenecks, have a detrimental effect on water treatment processes, and increase in Oil in Water levels higher than admissible specs for discharge or reinjection.\u0000 Several CEOR projects are introduced to producing fields where an established water treatment process already exists. These processes are initially designed to perform under a set of fluid and operating conditions. Polymer breakthrough can change the back produced water characteristics and impact the performance of the process. Upgrading of processes may require substantial investment. Chemical additives are widely considered as pragmatic alternative to improve water quality to desired levels. The selection of chemicals is very important as there are other associated challenges to be considered e.g. of the use of inorganic coagulants such as polyaluminum chloride (PAC) has been shown in studies to generate significant amounts of viscous sludge with low dry solids creating, sludge handing and equipment issues in the field.\u0000 In this study, a new product combination has been developed to solve some of the drawbacks of traditional chemical such as sludge production while maintaining the performance of treatment.\u0000 The composition of the product was determined through series of lab experiments and using design of experiments (DOE) methodology. The experiments were initially performed using a synthetic mixture of 400 parts per million (ppm) of hydrolyzed polyacrylamide (HPAM with hydrolysis degree ~ 30%) in saline water. The results were benchmarked to PAC and shown to produce a lower amount of sludge (25-50%) with the same performance in the same range of dosage (300-400 ppm). The sludge generated from the new combined product was also less viscous compared to the benchmark product. The investigation also revealed that a composition containing both inorganic/organic coagulant and cationic polymer improved performance. Results were validated with a field sample containing approx. 300 ppm of HPAM polymer. It was found that to generate less sludge and remove maximum total suspended solids, complete removal of polymer is not required.\u0000 This new product offers several benefits including a reduction in the operating costs (product dosage is about half of benchmark product, polyaluminum chloride), reduction in the chemical footprint, improves the operational efficiency of the water treatment process and allows to operate within their environmental specifications.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90074038","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":"Mukhaizna Steam Flood Project: Thermal Surveillance Practices and Log Response","authors":"Sultan AL-Qassabi, Mohammed Al Rahbi, Ali Al Habsi, Rashid Al Shaibi","doi":"10.2118/200090-ms","DOIUrl":"https://doi.org/10.2118/200090-ms","url":null,"abstract":"\u0000 Mukhaizna is a heavy oil field located in southern Oman. The heavy oil (700 to 3900 cP at reservoir conditions) was found at a true vertical depth of 2000 to 2460 ft, which is considered rather deep for a steam flood. Initial reservoir pressure was 1,300 psi, and the initial temperature was 122°F. The field has been developed with horizontal producers, vertical steam injectors, and vertical infill producers in patterns of about 67 acres in size. To date, 3000+ wells have been drilled in Mukhaizna field, and a huge amount of Petrophysical data has been acquired.\u0000 Petrophysical surveillance work provides monitoring of time lapse thermal efficiency sweeping, perforation picking strategies of hot, swept and cold zones, as well understanding open hole log response in thermal hot wells. Using this information, we were able to target the correct zones to improve the thermal sweep and increase oil production.\u0000 The first part of this paper will describe the open-hole log response in thermal wells and how perforation intervals are picked based on this log response. These perf picks were later corroborated with well production data to ensure alignment with well production performance.\u0000 The second part of this paper will present a field-specific correlation of steam quality measured at the separator with spinner surveys at wellhead injectors, aiming to estimate steam quality directly from a spinner survey without having to run a steam quality separator, which is time-consuming and involves extensive effort.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72841945","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":"Brine to Enhance the Transport of Encapsulated Petroleum Sulfonates Nanosurfactants Deeper into the High Temperature Carbonate Reservoirs","authors":"A. Gizzatov, Mohammed Kawelah, Afnan Mashat, A. Abdel-Fattah","doi":"10.2118/200222-ms","DOIUrl":"https://doi.org/10.2118/200222-ms","url":null,"abstract":"\u0000 Development of NanoSurfactants (NSs), encapsulated petroleum sulfonates, is in progress for use as one of the most cost efficient surfactants in chemical enhanced oil recovery (CEOR) applications under extreme conditions. This work provides a better understanding of NS transport though porous carbonate rocks and demonstrates how hot and salty brines can facilitate NS transport when compared to deionized (DI) water.\u0000 Transport of NSs at 90 °C in 57,000 ppm total dissolved solids (TDS) brine as well as NS components, petroleum sulfonate and zwitterionic co-surfactant, in 90 °C DI water through limestone core plugs was studied using a core flood apparatus. Effluent samples were measured for the total surfactant concentration using a total organic carbon (TOC) analyzer, and the dynamic retention values were calculated and compared. Structural integrity of NS assemblies before and after transport through the porous rock structure were studied using 1H Nuclear Magnetic Resonance (NMR) spectroscopy.\u0000 Petroleum sulfonate surfactants are unstable in hot brines with high concentrations of divalent ions, and therefore cannot be transported through porous rock structures. Transforming such unstable sulfonates into NS formulations can overcome these challenges. Dynamic retention results in water-wet limestone demonstrate that NSs can be successfully transported through 150 - 200 millidarcy (mD) reservoir rocks with retention values < 0.4 mg/g of rock. These values are 30-50% lower than the retention of NS components alone, which is < 0.7 mg/g, if measured at the same conditions using DI water. Much lower retention for NSs was observed in brines, when compared to its surfactant components in DI water. This can be attributed to the NSs nanostructure which is designed to encapsulate sulfonates closer to the core while efficiently dispersing in the brines by co-surfactants with zwitterionic heads located at the surface. High salinity brine also helps to screen surface charges present on the rock surface. NMR spectroscopy results confirm that the nano-assembled NS structure does not exhibit noticeable changes after core flood experiments and confirms that the formulation has great potential for CEOR applications.\u0000 Results presented in this work demonstrate that NS formulations made of assembled and dispersed nanocapsules enable the application of one of the lowest cost industrial surfactants for CEOR in hot and salty brines. This formulation in brines significantly reduces the loss of surfactants to the carbonate rock when compared to the same surfactant components in fresh water.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"2012 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73791046","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":"A Self-Adaptive Artificial Neural Network Technique to Estimate Static Young's Modulus Based on Well Logs","authors":"A. Mahmoud, S. Elkatatny, Abdulwahab Ali, T. Moussa","doi":"10.2118/200139-ms","DOIUrl":"https://doi.org/10.2118/200139-ms","url":null,"abstract":"\u0000 Static Young's modulus (Estatic) is an essential parameter needed to develop the earth geomechanical model, Young's modulus (E) considerably varies with the change in the lithology. Recently, artificial intelligence (AI) techniques were used to estimate Estatic for carbonate formation. In this study, artificial neural network (ANN) was used to estimate Estatic for sandstone formation.\u0000 In this study, the ANN design parameters were optimized using the self-adaptive differential evolution (SaDE) optimization algorithm. The ANN model was trained to predict Estatic from conventional well log data such as bulk density, compressional time, and shear time. 409 data points from Well-A were used to train the ANN model which was then tested using 183 unseen data from the same well and validated on 11 data points from a different well (Well-B).\u0000 The developed SaDE-ANN model estimated Estatic for the training data set with a very low average absolute percentage error (AAPE) of 0.46%, very high correlation coefficient (R) of 0.999 and coefficient of determination (R2) of 0.9978. And the Estatic values of testing data set were estimated with AAPE, R, and R2 of 1.46%, 0.998, and 0.9951, respectively. These results confirmed the high accuracy of the developed Estatic model.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73975389","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":"Improving Zonal Isolation and Cutting the Water Production with the Help of an Engineered Self-Healing Cementing System: A Case Study Review of the First Implementation of its Kind in Kuwait","authors":"B. Al-Khayyat, Meshari Al-Mudhaf, A. Saffar, Tarasankar Mitra, Ken Monteiro, Sarah Al-Safran, Saleh Gholoum, M. Al-Khaja, Jasim Ali, Fatemah Al-Rashed, Mohammad Alotaibi, Fahad Almunayes","doi":"10.2118/200299-ms","DOIUrl":"https://doi.org/10.2118/200299-ms","url":null,"abstract":"\u0000 In one of the prolific fields in Kuwait, achieving zonal isolation posed a big challenge mainly due to setting the production liner shoe close to the oil-water-contact zone. Cement bond logs from the primary cementing jobs were not acceptable due to contamination from intruding water leading to a high water-cut in the produced oil. We review the first implementation of a self-sealing Cementing System in Kuwait to improve zonal isolation and cutting the water production.\u0000 A comprehensive pre-job study was executed to engineer a suitable cementing system containing a swellable elastomer for oil-water-cuts with proper test in Lab. A novel HPHT multi-function test cell apparatus and procedure were utilized to measure in-situ ability of fractured cement specimens to seal oil-water-flows under the given simulated downhole conditions. Shrinkage or expansion of the set cement was also verified under pressure and temperature with a continuous test method run over several days. Thorough lab tests and Computational Fluid Dynamics simulations were run to enable a fit-for-purpose and robust cement slurry design ensuring proper placement of the cementing system in the well.\u0000 This paper will describe how this cement was designed and engineered in laboratory. It will also describe how the set up was made simulating a crack in cement specimen and injecting water cut oil reacts and provides desired results.\u0000 A calculated cement engineering approach was adopted to ensure better cement slurry placement and reduce the chances of slurry contamination. The test conditions were staged to replicate the most appropriate downhole conditions of pressure, temperature and simulated micro channel in the cement sheath. After the successful implementation of the self-sealing cementing system along the 7-in production liner in 2 wells, the corresponding cement bond log images showed hydraulic isolation and the production data from the wells indicated a reduction of nearly 50% in the water cut thus allowing a favorable oil production.\u0000 This technology is applied in other wells of this field and other fields also with good results. This is being continued to use in critical wells.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84712831","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":"Addressing Challenges for Consistent Improvement of Cement Bonds in South Oman Fields","authors":"Gluber Meza, Samiullah Satti, H. Al-Sabti","doi":"10.2118/200184-ms","DOIUrl":"https://doi.org/10.2118/200184-ms","url":null,"abstract":"\u0000 Short liner cementing is very common in Oman southern oil fields. Among the challenges one can find no mechanical separation between the fluids, cement and pre-flush volumes are relatively small leading or increasing the chances of contamination and requiring remedial cementing jobs with uncertain success.\u0000 As a result, poor cement bond log across the liner section were observed in more than 80% of all the cementing jobs.\u0000 An engineering approach was proposed for this scenario. First increase rheologies of the fluids using physics instead of chemistry to diminish the fluid contamination inside of the casing and create a better sweeping effect outside of the casing. Selecting the adequate solid size ratios of the weighting agent to reduce the possible loss circulation problems generated by higher friction pressure. Increasing the generation and ultimate compressive strength of the cement system and finally providing expansion properties to the set cement.\u0000 This paper presents the field CBL/USIT logs results and a case study showing the application and effectiveness of the technique proposed comparing with the previous approach in different wells.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85466253","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":"Data-Driven Integrated Reservoir Development of a Mature Condensate-Rich Gas Field in the Sultanate of Oman","authors":"Roeland van Gilst, Ahmed Al Kindi, Naila Al Balushi, Al Mutasem Abri, Ahmed Al Busaidy, Aida Al-Khusaibi","doi":"10.2118/200028-ms","DOIUrl":"https://doi.org/10.2118/200028-ms","url":null,"abstract":"\u0000 Recent observations indicate a distinct hydrocarbon composition change in a mature condensate rich gas field in the Sultanate of Oman, which will drastically change the next development decisions.\u0000 The new insights were a result of: 1) data analysis and visualization and 2) collaboration between Development Planning (DP), Well & Reservoir Management (WRM) and Exploration. Field data such as well tests, fluid samples and production logging tests were integrated with geological concepts to deliver reservoir models that could assist late field life decision making.\u0000 The outcome of the data analysis was summarized in the so-called \"Plumbing Diagram\", which combines reservoir architecture, structural elements, fluid fill and a reservoir connectivity analysis. The diagram was also used as a collaboration tool between Development, WRM and Exploration, which enabled the non-core team members to quickly understand the key uncertainties, risks and opportunities.\u0000 Field data indicated vertical changes in hydrocarbon composition across the field. These new observations were combined with exploration burial diagrams and thin section analysis from core data. This led to the insight that the gas field is not just rich in condensate, but has gone through various hydrocarbon charge stages starting with an initial oil charge. A recently drilled well confirmed the existence of the oil charge with solid bitumen indicating a subsequent thermal cracking phase.\u0000 Integration with wire line log evaluations made it possible to define two field-wide fluid zones, referred to by the team as: 1) Free Gas (FG) and 2) Condensate Rich Gas (CRG). The split of the two fluid zones will have a major impact on the field Development and WRM strategy as the focus is shifting towards development of the CRG zone, which is more challenging mainly due to the fluid fill mixture of oil, bitumen, gas and condensate.\u0000 This paper describes how field data, observations and collaboration between teams improved the total hydrocarbon system understanding driving the future development decisions. The success of the changes in the development and WRM strategy will serve as blueprint for condensate rich gas fields with a similar burial and charge history in the north of Oman.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90047491","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 Organic Acids Implementation in Stimulating Tight Gas Reservoirs: A Case Study on Sarah Sandstone Formation","authors":"Ellewa Ahmed Elsheikh, T. Moawad, A. Alnetaifi, Abdulrahman Alquraishi, Y. Almutawea","doi":"10.2118/200242-ms","DOIUrl":"https://doi.org/10.2118/200242-ms","url":null,"abstract":"\u0000 Sandstone formations are yet stimulated with mud acid when matrix acidizing is most competent. In terms of high-pressure high-temperature (HP-HT) conditions, the corrosive impact of hydrochloric (HCl) acid prompted the need to explore other alternatives to mud acid. This study examines the efficiency of organic acids in stimulating Sarah sandstone, a tight gas formation of potential.\u0000 Two Berea cores were first exploited to investigate the optimum and most efficient injected acid volume. The mineralogy of Sarah formation was identified using X-ray diffraction (XRD) aided by Scanning Electron Microscopy (SEM). Formation mineralogy led to the selection of acetic-HF and oxalic-HF as proper acids for stimulation experiments. Bentonite water-base mud was used to alter the permeability of three fresh Sarah sandstone core samples. The organic-HF acids were used to stimulate two core samples, while mud acid was tested in the third core for comparison. Energy-dispersive X-ray spectrometer (EDX) and SEM were utilized to study the impact of acids on porous media.\u0000 Experiments conducted in Berea core samples led to the execution of five pore volumes (PV) of preflush and one PV of main treatment as the optimum volume during the acidizing trials. XRD and SEM identified pore-filling clay minerals causing the low permeability of Sarah formation. Furthermore, the water-base mud injected decreased the permeability further by 80%. Oxalic-HF and acetic-HF mixtures recovered the initial permeability of core samples by 46% and 35% respectively. SEM-EDX results showed how organic acids have partially unblocked the pathways of the structural pores leading to permeability enhancement.\u0000 This research not only recommends the use of oxalic-HF acid for acidizing Sarah sandstone formation but also spotlights the ability of organic acids employment as preflush in hydraulic fracturing operations.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89808228","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}