The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Xiao, Wenlian (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University (Corresponding author)) | Yang, Yubin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Bernabé, Yves (Earth, Atmospheric and Planetary Sciences Department, Massachusetts Institute of Technology) | Lei, Qihong (PetroChina Changqing Oilfield Company) | Li, Min (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Xie, Qichao (PetroChina Changqing Oilfield Company) | Zheng, Lingli (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Liu, Shuaishuai (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Huang, Chu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Jinzhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Ren, Jitian (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Summary A significant amount of associated gas has been produced from shale oil reservoirs in the Ordos Basin, northern China, in recent years, which has provided an opportunity for using low-cost, associated gas in enhanced oil recovery (EOR) projects. However, there are few other reports of EOR projects in shale oil reservoirs using associated gas, and a quantitative evaluation of the technique is needed. Therefore, we conducted associated gas and waterflooding experiments in shale oil samples at constant and gradually increasing injection pressure while monitoring the spatial distribution of movable and residual oil by means of nuclear magnetic resonance (NMR) technology. Before the injection experiments, we performed mercury intrusion tests and measured the NMR transverse relaxation time, T2, of fully saturated samples to characterize the pore-throat size distribution of rock samples. Furthermore, we established a novel and robust mathematical model based on a fractal description of the pore space and a capillary tube model to determine the lower limit of the pore radius of movable oil, rc, during gas- and waterflooding. We observed that the oil recovery factor at a low injection pressure (i.e., 0.6 MPa) during the associated gasflooding was lower than that during waterflooding under both constant pressure injection mode and gradually increasing pressure injection mode. However, the performance of associated gasflooding was greatly improved by increasing the injection pressure. High injection pressure indeed produced a higher oil recovery factor, thinner residual oil film thickness, and smaller rc during associated gasflooding than during waterflooding under both injection modes. These differences in behavior appear to be linked to dissimilarities in flooding mechanisms at high and low injection pressures. Our main conclusion is that associated gasflooding at high injection pressure (i.e., 6 MPa) has a better potential for enhancing the oil recovery factor than waterflooding in shale oil reservoirs.
Wang, Kai (College of Petroleum Engineering, China University of Petroleum (East China)) | Luo, Mingliang (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Li, Mingzhong (College of Petroleum Engineering, China University of Petroleum (East China)) | Kang, Shaofei (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China) (Corresponding author)) | Li, Xu (College of Petroleum Engineering, China University of Petroleum (East China)) | Pu, Chunsheng (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Liu, Jing (College of Petroleum Engineering, China University of Petroleum (East China))
Summary Hydrolyzed polyacrylamide/chromium III [HPAM/Cr (III)]-acetate gel treatment is an effective way for conformance control and water shutoff in various mature reservoirs around the world. However, it encounters severe challenges in the fractured extralow permeability reservoirs with the performance varying between success and failure when channeling caused by through-type fracture exists. The through-type fracture channel that connected injection to production is formed by the connection of hydraulic and natural fractures. This research takes the extralow permeability reservoir in the Ordos Basin as the background, and under the characterization of HPAM/Cr (III)-acetate gel, the effect of a preflush crosslinker on improving gel-plugging performance was studied via experiment, and the corresponding gel-plugging process was optimized. Experimental results showed that the preflush crosslinker could effectively improve the blocking strength and stability of HPAM/Cr (III)-acetate gel for through-type, large-opening fractures. Moreover, a high-quality “gel wall” was formed based on the preflush crosslinker; it worked as a barrier within the fracture and was the key to successfully blocking the millimeter-opening fracture. Under the experimental conditions, the optimized plugging process was as follows: The crosslinker was preflushed 24 hours in advance, and the gelant was injected in three slugs, with the volume of the first slug being 0.5 pore volume (PV). A field trial conducted in Ansai Oil Field demonstrated the potential of HPAM/Cr (III)-acetate gel and its plugging capability of optimized plugging method based on the preflush crosslinker to block through-type water channeling. This research provides valuable experimental data and theoretical guidance for conformance control and water shutoff of HPAM/Cr (III)-acetate gel treatment in fractured extralow permeability reservoirs.
Liu, Yongjun (Shell China Exploration and Production Company Ltd) | Zhao, Hongkai (Shell China Exploration and Production Company Ltd) | Wang, Jichang (Shell China Exploration and Production Company Ltd) | Sun, Jiacai (PetroChina Changqing Oilfields Company) | Luo, Lei (PetroChina Changqing Oilfields Company) | Lu, Zaohua (PetroChina Changqing Oilfields Company) | Zhang, Xiaodong (PetroChina Changqing Oilfields Company) | Jiang, Tao (CNPC Chuanqing Drilling Engineering Company Limited) | Zhu, Xuanlu (CNPC Chuanqing Drilling Engineering Company Limited) | Zhang, Zhenhuo (CNPC CCDC DPRI)
Abstract China Changbei block development is an unconventional tight gas project in China Ordos basin. The main pay zone of Changbei is braided river sedimentation with inconsistency of sandstone. Well stimulation with hydraulic frac was the predominant concept for tight gas development in the basin with low individual well producing rate. Innovative Dual-Lateral horizontal well concept was selected for Changbei block thin gas reservoir development. Each cluster planned 3 Dual-Lateral horizontal wells which could cover a 3 km radius circle drainage area. The Dual-Lateral well spud with 16" hole to about 600m to secure top formation, then continue with 12-1/4" hole section landing in reservoir formation at around 3,400m AHMD (2,900m TVD) and cased off with 9-5/8" casing. Two 8-1/2" lateral legs, with each being turned for around 45 degrees in azimuth to separate from each other, string up as many as sand bodies in designed 2,000m leg length in reservoir section to maximize production. The Dual-Lateral horizontal well design proven to be successful for China Changbei tight gas development. By 2022, Changbei completed in total 57 Dual-Lateral horizontal wells and maintained productivity over 3.2BCM per year for more than 14 years, played an important role for China gas supply. This paper detailly described the well design and execution of Dual-Lateral horizontal wells including drilling challenges and countermeasures including casing exit and open hole sidetrack practices, hole cleaning, drill pipe and BHA selection, etc. The paper will give a full picture on Dual-Lateral horizontal wells construction.
Li, Gaoren (1. Research Institute of Exploration & Development, PetroChina Changqing Oilfield) | Zhang, Wei (2. National Engineering Laboratory of Exploration and Development of Low Permeability Oil and Gas Fields, PetroChina Changqing Oilfield) | Liu, Die (Shenzhen Operating Company of Well-Tech Department, China Oilfield Services Ltd.) | Li, Jing (1. Research Institute of Exploration & Development, PetroChina Changqing Oilfield) | Li, Cheng (2. National Engineering Laboratory of Exploration and Development of Low Permeability Oil and Gas Fields, PetroChina Changqing Oilfield) | Li, Jiaqi (Research Institute of Geophysics, Research Institute of Exploration and Development, PetroChina Xingjiang Oilfield) | Xiao, Liang (1. Research Institute of Exploration & Development, PetroChina Changqing Oilfield)
Abstract Pore structure described the macroscopic pore size and microscopic pore connectivity. It heavily determined formation quality and seepage capacity, and thus associated with permeability. Generally, ultra-low permeability to tight sandstone reservoirs were always affected by complicated pore structure and strong heterogeneity. Characterizing pore structure was of great importance in improving tight sandstone reservoir evaluation and validity prediction. Nuclear magnetic resonance (NMR) logging was considered to be valuable in pore structure prediction only in exploration wells because plenty of NMR logging data was acquired in key wells. However, methods that established in exploration wells cannot be directly extended into development wells due to the limitation of quantity of NMR data. In addition, NMR logging was only usable in pore structure characterization in water saturated layers, it cannot be directly used in hydrocarbon-bearing reservoirs. In this study, to establish a widely applicable pore structure characterization method that can be used not only in exploration wells, but also available in development wells to improve formation validity evaluation and high-quality formation identification in Triassic Chang 8 Formation of Shunning Region, Eastern Ordos Basin, we established a technique to synthetize pseudo-Pc curve from geophysical logging data by using deep learning method. This technique was raised based on the morphological feature analysis of mercury injection capillary pressure curves. We found that the applied mercury injection pressures were the same for all core samples during mercury injection experiments, the pore structure difference for all core samples was determined by injected mercury content (SHg) under the same Pc. Hence, once we predicted mercury content under every Pc, pseudo-Pc curve can be synthetized by combining predicted mercury content and known Pc. Constructing pseudo-Pc curve was translated as predicting mercury content. To establish a reasonable model that can be used in development wells, where only conventional logging data was available, we analyzed relationships among mercury contents under every mercury injection pressure and geophysical logging data. This analysis was raised based on heat map of decision tree technique, and the experimental data of 115 core samples that drilled from Triassic Chang 8 Formation in Shunning Region was used. Finally, we found that SHg under 15 capillary pressure was heavily related to porosity and deep and shallow resistivity. Based on this perfect relationship, we established a model to predict 15SHg from porosity and deep and shallow resistivity by using deep learning method of XGBoost. In this deep learning method, 92 clusters of core analysis data (accounting for 80.0% of the total), were used as training samples, and the rest 20.0% was retained as samples for verification. Meanwhile, relationship between SHgs under two adjacent mercury injection pressures was also closely related. Hence, after SHg under 15 Pc was predicted from conventional logging data, the other SHgs can be calculated by using step iterative method. In addition, considering the used input porosity in XGBoost was also difficult to be estimated based on statistical method, neutron, density, interval transit time (Δt) and delta natural gamma ray (ΔGR) were chosen as input parameters, and XGBoost was used to predict porosity from well logging data. Based on predicted porosity and deep and shallow resistivity, pseudo-Pc curves were consecutively synthetized to characterize pore structure of tight Chang 8 sandstone reservoirs. Meanwhile, pore throat radius distribution, and pore structure evaluation parameters were also calculated, comparison of predicted pore structure evaluation parameters and core derived results illustrated that calculation accuracy reached to 86.4%. In addition, we determined two pore throat radius cutoffs to classify pore throat radius into three parts, which represented small, intermediate and large pore throat sizes, separately. The relative contents of each type of pore throat sizes were calculated, separately. A parameter of formation validity indication was raised to evaluate formation pore structure. Relationship between formation validity indication and daily liquid production per meter was established, and formations were classified into three types. The first and second types of formations were effective formations that contained substantial hydrocarbon production capacity, and the third type of formation was dry. Our raised method and technique were well used to improve tight reservoirs characterization and evaluation in Chang 8 Formation of Shunning Region, and it would also be valuable in indicating the distribution of effective tight sandstones for formations with similar properties.
Liu, Yongjun (Shell China Exploration & Production Company Ltd) | Li, Jinsong (Shell China Exploration & Production Company Ltd) | Lin, Dong (Shell China Exploration & Production Company Ltd) | Sun, Jiacai (PetroChina Changqing Oilfields Company) | Luo, Lei (PetroChina Changqing Oilfields Company) | Chen, Guiyang (PetroChina Changqing Oilfields Company) | Li, Peng (PetroChina Changqing Oilfields Company) | Ding, Peng (PetroChina Changqing Oilfields Company) | Chen, Zhiqiang (Chengdu Best Diamond Bit Company Ltd) | Xia, Yang (Chengdu Best Diamond Bit Company Ltd) | Xiao, Rui (Chengdu Best Diamond Bit Company Ltd)
Abstract Dual lateral horizontal wells were drilled for China Changbei tight gas development in Ordos basin. The horizontal 8 ½" hole section is the most challenge part for efficient well construction due to the hardness and abrasiveness of the consolidated sandstone rocks. Optimized drilling performance requires the matching of appropriate drill bit technology to an application for the formation to be drilled, which can be an engineering challenge. Various types of drill bits, including TCI, PDC and Hybrid type bits are used in Changbei for continuous performance improvement. The 8 ½" hole section consists of hard and abrasive sandstone, interbedded claystone, and conglomerates. Most drill bits suffered short runs due to severe wear in the outer region of the bit including Gauge and Shoulder area, even lost cones for TCI and Hybrid bits. With collaborations from operators and bit vendors, based on dull review and data analysis, a new type of PDC bit was designed with advanced cutter technology. The new design was developed to increase ROP and run length, avoiding unnecessary trips in the challenging formations and improved the drilling efficiency. The new designed PDC bit adopted short profile design, reversed circle cutter placement pattern, balanced the aggressiveness and durability with backup cutters and DOC control. PDC cutters was used for passive gauge protection to overcome the wear out due to formation abrasion. The field trials were very successful. The new designed PDC bit improved 30% on ROP and 10% on footage per bit run than offset Hybrid bits. Moreover, the new designed PDC bit eliminated lost cone risks of TCI and Hybrid bits, which was happened a couple of times in Changbei and caused tremendous NPTs for fishing and sidetracks. This article will describe the bit performance improvement journey of Changbei tight gas field. Even with a long period of time staying on plateau, step changes still possible with new technology deployment and continuous improvement mindset.
Zang, Yuxi (China University of Petroleum, Beijing) | Wang, Haizhu (China University of Petroleum, Beijing) | Abderrahmane, Hamid Ait (Khalifa University) | Wang, Bin (China University of Petroleum, Beijing) | Wang, Tianyu (China University of Petroleum, Beijing) | Tian, Shouceng (China University of Petroleum, Beijing) | Stanchits, Sergey (Skolkovo Institute of Science and Technology) | Cheremisin, Alexey (Skolkovo Institute of Science and Technology)
Abstract An improved recovery technique using carbon dioxide (CO2) pre-pad energized fracturing is presented to address the issue of low recovery in depleted development of shale reservoirs in the Ordos Basin. This study quantitatively evaluates the effect of CO2 pre-pad energized fracturing under different engineering and geological parameters. The geological model of the target block was created in GOHFER using field logging data from the Ordos Basin oilfield. By coupling the reservoir simulator CMG, a three-dimensional wellsite-scale long horizontal mechanism model was established, considering the artificial hydraulic fracture model. The influence of engineering parameters and geological parameters on CO2 distribution was quantitatively evaluated. According to the outcomes of the simulation, the production potential of shale oil reservoirs can be significantly increased by using the CO2 pre-pad energized fracturing development method. Important engineering factors affecting the stimulation include the CO2 injection volume and soaking time, and the geological factors include the porosity, permeability, and layering. When the injection amount reaches a certain level, the growth of CO2 sweep area decreases. With the increase of immersion time, the CO2 sweep range gradually increases. Reservoir porosity and permeability affect CO2 sweep in the lateral direction. Considering the front slick water fracturing fractures, the impact on the CO2 sweep range is not apparent. Combined with GOHFER and CMG numerical simulation software, this study can realize the refined description of reservoirs considering artificial hydraulic fracture networks. According to the CO2 injection range, the effect of CO2 pre-pad energized fracturing under different engineering and geological conditions can be quantitatively evaluated. This study can be used as a reference CO2 pre-pad energized fracturing of shale oil reservoirs in the Ordos basin.
Wang, Yang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Yao, Yuedong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Chen, Jieyi (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Yang, Jian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Wang, Lian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China)
Abstract As one of the subtle reservoirs, low-resistivity-low-contrast (LRLC) pay zones are crucial potential exploration objective in Ordos basin. However, since its resistivity similarity to the adjacent water zones, and the genetic mechanism is complex, thence, LRLC pay zones still produce hydrocarbon at minimum resistivity contrast between hydrocarbon-bearing intervals and water-wet or shaly zones. So, if LRLC pay zones could be accurately identified only by conventional logging curves, it would bring new reserves to the development of Yanchang Oilfield. Focusing on the difficulties in well logging identification of Chang 2 LRLC pay zones in Zhidan area of Ordos basin, the work on logging identification of low resistivity pay zones in this area is carried out by processing field data such as drilling coring, well logging curves, oil testing and daily production data. Meanwhile, combined with the experimental data such as NMR experiments, rock electrical experiments, laser particle size and cation exchange capacity experiments, we form an integrated workflow based on petrography, rock typing and petrophysical methods, and deal with the identification, characterization and evaluation of LRLC pay zones. This study indicates that under the deposition environment of delta plain subfacies, Chang 2 reservoir is dominated by medium-fine-grained feldspar sandstone, and the pore structure is extremely complex due to the strong compaction. Therefore, the key cause for LRLC pay zones is the high salinity of formation water, accompanied by secondary reasons such as complex pore structure, and additional electron conductivity of the clay. In order to effectively identify the pay zones, we establish a set of suitable logging curve interpretation models based on the "four properties" relationship and test them with oil testing data, which could improve the accuracy of these models. Finally, the "apparent formation water resistivity - deep induced resistivity" cross-plot, the adjacent water zone comparison and the multivariate discriminant methods are selected to be suitable for Chang 2 low resistivity pay zones in the area. And these methods could help engineers to better estimation of water saturation in the low resistivity pay zones and accurately determine the target layer by using only limited set of well log data (conventional well logging data). In this work, three effective logging identification methods have been proposed to determine the advantaged pay zones from qualitative or quantitative perspectives. Through real block verification, these methods could effectively improve the coincidence rate of logging identification, and would provide bases for selecting the target layers in original development areas. More importantly, the results may offer new perspectives for risk assessment and target layer determination of other similar low resistivity reservoirs exploration and development.
Tao, Liang (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Qi, Yin (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Tang, Meirong (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Ye, Kai (Chuanqing drilling Engineering Company, Limited, Changqing Downhole Technology Operation Company, Petrochina Company Limited) | Wang, Deyu (Oil and Gas Technology Research Institute Changqing Oilfield Company, Petrochina Company Limited) | Halifu, Mirinuer (Gubkin Russian State University of Oil and Gas (National Research University)) | Zhao, Yuhang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Abstract The continental shale oil reservoirs usually have strong heterogeneity, which make the law of fracture propagation extremely complex, and the quantitative characterization of fracture network swept volume brings great challenges. In this paper, firstly, the grey correlation analysis method is used to calculate the correlation coefficient between different parameters and microseismic monitoring volume (SRV), and the key factors affecting SRV are identified. Secondly, the relationship between key geological engineering parameters and SRV is established by using the method of multiple linear regression, and the relationship is further corrected by productivity numerical simulation method, and the empirical formula for quantitative characterization of fracture network swept volume(FSV) is established. Finally, according to the field production of big data, the fitting chart of the accumulated oil production and the FSV is established, and the production of horizontal well is further predicted according to the fitting formula. The study results shown that the main factors affecting the SRV were fracturing fluid volume, fracture density, brittleness index, pump rate, horizontal stress difference, net pay thickness and proppant amount.The FSV in the study area was positively correlated with the cumulative oil production of the horizontal well. With the increase of the FSV, the accumulated oil production increased at first and then tended to be stable, and the optimal FSV was 760 ~ 850*10m. The prediction method was verified by the typical platform in the field to be accurate and reliable. It can provide scientific basis for the productivity prediction of horizontal wells in shale oil reservoirs.
Wang, Yang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Yao, Yuedong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Wu, Hao (CNOOC Research Institute Co., Ltd., Beijing, China) | Dai, Jinyou (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Wang, Lian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China) | Mu, Zhongqi (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing, China)
Abstract Low-production wells can often be found during the process of gas field production, particularly in low-permeability and tight gas reservoirs. In the Jingbian gas field, some wells (defined as abnormal-low-production wells (ALPWs)) have a much earlier decline period, a larger decline rate, and greater remaining dynamic reserves. In this paper, the low-production gas wells in the Xiagu gas reservoir of Jingbian gas field are taken as the research object, and the existing static and dynamic data of the gas field are comprehensively studied. To enhance the production of the ALPWs, this study focused on the production characteristics, decline causes, and applicable countermeasures of the ALPWs. Static and dynamic data from 57 low-production wells in the Xiagu gas reservoir were analyzed. In addition, differences in production characteristics between traditional low-production wells and the ALPWs are compared using production, pressure and other development indicators. Furthermore, the rapid identification and selection criterion of the ALPWs is established by implementing the producing indexes of the ALPWs. The study shows that several characteristics of the ALPWs can be determined by the production-pressure limiting method. The main determination criteria are listed as follows: The annual production decline rate is more than 20% (far greater than the normal annual decline rate of 5%). The single gas well continues to produce for more than 30 days with a daily production of 10000 m. The tubing-casing pressure differential is greater than 2.5MPa. The most significant characteristic is that the remaining dynamic reserves of the ALPWs are greater than 250 million m. All the above characteristics demonstrate that the ALPWs might still have great production potential and the causes for the abnormal-low-production could be analyzed by the node analysis and the IPR curve. Moreover, the bottom-hole water loading and wellbore plugging are the main causes of the abnormal-low-production. This research helps the engineers identify 57 ALPWs in Jingbian gas field, and puts forward adaptive countermeasures for the abnormal production decline causes, which helps the gas field achieve the goal of increasing production and stabilizing productivity. And it could be applied in other similar low-production gas wells with hydraulic fractures in tight gas reservoirs worldwide, and could provide research reference for the progress of enhancing productivity from the low-production gas wells.
Zhang, Jianguo (PetroChina Changqing Oilfield Co., CNPC) | Wang, Zhenjia (PetroChina Changqing Oilfield Co., CNPC) | Lan, Yifei (PetroChina Changqing Oilfield Co., CNPC) | Zhao, Chenyang (PetroChina Changqing Oilfield Co., CNPC) | Liu, Jinhua (PetroChina Changqing Oilfield Co., CNPC)
Abstract Objectives/Scope A low-permeability lithological reservoir was successfully put into operation in 2015 as a gas storage system. The field S2 Underground Gas Storage (UGS) is located in the Ordos Basin and is primarily alithological trap, with low permeability, high heterogeneity, and no obvious seal boundaries. Based on low permeability, low abundance, low vertical wells productivity, low pressure coefficient, serious skin damage in the bottomhole during drilling and completion, strong heterogeneity and unclear lithological boundaries, low control of injection-withdrawal well patterns, the working gas volume and operating efficiency of S2 UGS underperformed relative to modeled expectations. The technical solutions to improve the working gas volume of S2 USG focused upon: well pattern optimization, well placement, stimulation treatment, infillings, and increasing of operating maximum pressure. The results demonstrate that if reasonable technical solutions are adopted, even poor and low-quality storage reservoirs with low permeability, and strong heterogeneity, can be utilized as natural gas storage targets. This discussion provides an overview of approaches used in the Ordos Basin to make operation of S2 UGS more efficient. The development of this project, particularly regarding the operation processes and the resulting adjustments, are noteworthy. The development of such UGS reservoirs require new insights into the performance criteria which can be applied to other reservoirs in the future.