SPE Production & Operations最新文献

{"title":"Intelligent Approach for Gas-Oil Separation Plant Oil Recovery Enhancement","authors":"Ala AL-Dogail, R. Gajbhiye, Mustafa Alnaser, Abdullatif Alnajim, M. Mahmoud","doi":"10.2118/210565-pa","DOIUrl":"https://doi.org/10.2118/210565-pa","url":null,"abstract":"\u0000 The present practice is to operate the gas-oil separation plant (GOSP) at the predetermined set of conditions obtained during the design stage. These predetermined sets of conditions are fixed and do not account for the effects due to changes in the ambient temperature (Ta), resulting in low recovery and profitability. The variation of Ta highly affects the separation process, where Ta varies greatly from summer to winter. Thus, this study proposes an intelligent approach to maximize profitability by improving the oil recovery through optimization of low-pressure production trap (LPPT) and high-pressure production trap (HPPT) accounting for the changes in the Ta. This work also proposes an advisory system for guiding the operation team to set the HPPT/LPPT pressure at an optimal value that accounts for the changes in Ta for maximizing the oil recovery.\u0000 To generate the data accounting for the variation in Ta, a GOSP model was developed using the OmegaLand dynamic simulator. A typical Saudi Aramco GOSP parameter was used for the design. The oil recovery was obtained for the various runs of simulation for the representative range of HPPT/LPPT pressure over a wide range of Ta. Then, artificial intelligence (AI) techniques were applied to determine the optimal pressure of LPPT and HPPT units, and an intelligent advisory system is developed based on the correlation obtained for the optimal set of pressure according to the variation in Ta.\u0000 Results show that at constant HPPT and LPPT pressure, liquid recovery decreases with an increase in Ta, suggesting that readjustment in HPPT or LPPT operating pressure can counter the temperature changes to improve the oil recovery. The analysis of the results reveals that at a fixed value of Ta and LPPT pressure, the oil recovery increases with an increase in HPPT pressure up to the optimal value of HPPT pressure and then decreases above the value of optimal HPPT pressure.\u0000 Similarly, when the HPPT pressure and Ta are fixed, the oil recovery increases with an increase in LPPT pressure until it reaches the optimal value and then decreases above the value of optimal LPPT pressure. The improvement in the oil recovery signifies the existence of optimal pressure conditions for HPPT/LPPT separators at which maximum oil recovery can be obtained. This study shows the novel way to incorporate the changes in the ambient condition by optimizing LPPT/HPPT operating pressure for enhancing the liquid recovery of the GOSP plant. The advisory system developed from this study maximizes the oil recovery by determining the optimal set of operating conditions for the HPPT/LPPT separators.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121909799","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":"Airborne Trace Gas Remote Sensing and Surface Mobile In Situ: A Novel Tool for the Study of Structural Geological Controls from a Producing Oil Field","authors":"I. Leifer, C. Melton, D. Tratt, K. Buckland","doi":"10.2118/209799-pa","DOIUrl":"https://doi.org/10.2118/209799-pa","url":null,"abstract":"\u0000 Accurate and representative determination of greenhouse gases (GHG) from oil and gas (O&G) production facilities requires high-spatial-resolution data, which can be acquired by airborne imaging spectrometers. However, assessment of nonmethane hydrocarbon emissions, which are far less amenable to remote sensing, requires mobile surface in-situ measurements (e.g., a mobile air quality laboratory).\u0000 Field in-situ measurements and airborne thermal infrared spectral imagery were acquired for three producing California oil fields (Poso Creek, Kern Front, and Kern River) located next to each other on 14 September 2018. In addition, a profile ascending a nearby mountain collected in-situ data for the Round Mountain oilfield. Plume methane to ethane ratios were consistent within different regions of the field and differed between these fields in a manner related to field geological structures.\u0000 Data acquired by an airborne thermal infrared imaging spectrometer, Mako, in 2015 and 2018 showed most emissions were from distant plumes in the Kern Front and Poso Creek fields. The spatial distribution of detected plumes was strongly related to faults, particularly active faults, which are proposed to stress infrastructure, leading to higher fugitive emissions and/or emissions from natural migration pathways (seepage). Additionally, the spatial distribution of detected plumes suggested unmapped faults. Thus, high-sensitivity imaging spectroscopy can improve understanding of reservoir geological structures that impact hydrocarbon migration and field operations, highlighting the potential for a novel reservoir management tool.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133044617","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":"Mechanical Characteristics of Cluster Perforation String under Running Process in Horizontal Wells with Unconventional Oil/Gas Reservoirs","authors":"Xiaoqiang Guo, J. Liu, Zhigang Du, Kai Tang, D. Cao, Zuqing He","doi":"10.2118/209817-pa","DOIUrl":"https://doi.org/10.2118/209817-pa","url":null,"abstract":"\u0000 To improve the safety of cluster perforating tubing strings in horizontal wells with unconventional oil/gas reservoirs, a passing capability analysis model for cluster perforation string in a wellbore is established, in which the friction between downhole tools and borehole wall, fluid resistance, wellbore geometric constraint, and tool variable cross section were accounted for. The model is solved via geometric analyses and the beam-column theory. Then, the cable pump thrust test is carried out in three shale gas wells in South Sichuan, and comparing the measured data with the theoretical calculation results, the correctness of the theoretical model is verified. Based on that, the influences of the cluster numbers, the perforating gun types, the well section length, and the well types on the mechanical characteristics of the cluster perforation string are systematically analyzed. The results obtained demonstrate that, first, the number of perforating gun clusters should be as small as possible when the azimuth angle or well inclination angle changes greatly. In case of a small change of azimuth or deviation angle, the number of perforation gun clusters can be appropriately increased to improve the operation efficiency. Second, when the deviation angle and azimuth angle change greatly in field operation, it is recommended to use a small perforating gun to ensure the smooth running of the perforating string. When a large perforating gun is needed in the field, it is necessary to optimize the well trajectory (reduce the location of the big dogleg in wellbore) to ensure the safe running of the tubing string. Third, in the field well trajectory optimization design, the position of well inclination angle change and azimuth angle change should be staggered to improve the trafficability of perforating tubing strings on-site. Moreover, when increasing the well sections, the position of the knee point should be optimized to be smoother, and the change rate of the parameter value of the well trajectory should be reduced. The research results provide a theoretically sound guidance for designing and practically sound approach for effectively improving the service life of perforating tubing strings in horizontal wells with unconventional oil/gas reservoirs.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"103 4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"113971436","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":"Design of Steam Alternating Solvent Process Operational Parameters Considering Shale Heterogeneity","authors":"Zhiwei Ma, L. Coimbra, J. Leung","doi":"10.2118/210557-pa","DOIUrl":"https://doi.org/10.2118/210557-pa","url":null,"abstract":"\u0000 The steam alternating solvent (SAS) process involves multiple cycles of steam and solvent (e.g., propane) injected into a horizontal well pair to produce heavy oil. These solvent-based methods entail a smaller environmental footprint with reduced water usage and greenhouse gas emissions. However, the lack of understanding regarding the influences of reservoir heterogeneities, such as shale barriers, remains a significant risk for field-scale predictions. Additionally, the proper design of the process is challenging because of the uncertain heterogeneity distribution and optimization of multiple conflicting objectives. This work develops a novel hybrid multiobjective optimization (MOO) workflow to search a set of Pareto-optimal operational parameters for the SAS process in heterogeneous reservoirs.\u0000 A set of synthetic homogeneous 2D is constructed using data representative of the Cold Lake reservoir. Next, multiple heterogeneous models (realizations) are built to incorporate complex shale heterogeneities. The resultant set of SAS heterogeneous models is subjected to flow simulation. A detailed sensitivity analysis examines the impacts of shale barriers on SAS production. It is used to formulate a set of operational/decision parameters (i.e., solvent concentration and duration of solvent injection cycles) and the objective functions (cumulative steam/oil ratio and propane retention). The nondominated sorting genetic algorithm II (NSGA-II) is applied to search for the optimal decision parameters. Different formulations of an aggregated objective function, including average, minimum, and maximum, are used to capture the variability in objectives among the multiple realizations of the reservoir model. Finally, several proxy models are included in the hybrid workflow to evaluate the defined objective functions to reduce the computational cost.\u0000 Results of the optimization workflow reveal that both the solvent concentration and duration of the solvent injection in the early cycles have significant impacts. It is recommended to inject solvent for longer periods during both the early and late SAS stages. It is also noted that cases with higher objective function values are observed with more heterogeneities. This work offers promising potential to derisk solvent-based technologies for heavy oil recovery by facilitating more robust field-scale decision-making.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130807072","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":"Electrical Submersible Pump Design Enhancements for Hydrogen Sulfide Harsh Environments","authors":"Mohammed Al-Khalifa, Rui Pessoa Rodrigues, Derek Sinclair","doi":"10.2118/209832-pa","DOIUrl":"https://doi.org/10.2118/209832-pa","url":null,"abstract":"\u0000 Electrical submersible pumping (ESP) remains the preferred artificial lift method for high rate production when technically viable. ESP, on the other hand, is sensitive to downhole conditions and pumped fluid. Sour fields, in particular, are considered as a major challenge for producing facilities and well completion elements. Reservoirs producing fluids with hydrogen sulfide (H2S) present a special challenge to ESP systems.\u0000 This paper uses ESP field observations and pulled equipment findings from many dismantle inspection and failure analyses (DIFAs). The findings confirmed H2S behavior and root causes of electrical and mechanical failures within multiple ESP components. The outcome of these investigations and the recommended system upgrades to enhance ESP reliability in corrosive environments will be illustrated.\u0000 Critical ESP system materials will deteriorate and fail when subjected to sour environments. H2S can penetrate the pump’s cable insulation, attack the copper, and react to form copper sulfide, resulting in electrical failure. It can also permeate the seal bags and o-rings, diffuse in the seal dielectric oil, and attack the bronze and copper components in the seal and the motor. To improve reliability, a new version of motor lead extension (MLE) using three individually armored connectors and a seal with H2S sacrificial anode scavenger inside each chamber were introduced. The improved design encapsulated the insulated conductors individually within metal tubes made of high nickel alloy. The tubes can be terminated individually at the motor and above the production packer with proven swage type connectors.\u0000 By utilizing high nickel alloy tubes as barriers against H2S and removing all connections below the packer, the H2S effect has been eliminated. On the other hand, the seal with H2S passive scavenger will retain most of the H2S in the dielectric oil before it reaches the motor. These novelty technologies resulted in a threefold improvement, leading to longer up time, less workover jobs, and more sustainable production.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131201386","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":"Liquid Loading in Natural Gas Vertical Wells: A Review and Experimental Study","authors":"Maziad Alsanea, Camilo Mateus-Rubiano, H. Karami","doi":"10.2118/209819-pa","DOIUrl":"https://doi.org/10.2118/209819-pa","url":null,"abstract":"\u0000 Liquid loading in natural gas wells is one of the main causes of decline and eventual cease of production. Identifying the onset of liquid loading and its impacts on production is vital in production optimization of gas wells. In this study, a new state-of-the-art experimental facility is used to analyze two-phase flow parameters, such as liquid and gas velocities, pressure drop, liquid holdup, and flow pattern, and study the onset of liquid loading. Experiments are conducted using air and water in a 0.0508-m (2-in.) internal diameter (ID) vertical flow loop. The facility is designed to eliminate any source of disruption to the flow in a temperature-controlled indoor environment to avoid changes in fluid properties. A wide range of data are collected related to the onset of liquid loading and in the churn region. The acquired data are compared with other studies to ensure the accuracy and repeatability of the tests.\u0000 A quantitative method is developed to predict the onset of liquid loading, namely, the positive frictional pressure gradient (negative pressure drop). A comparison is made between the visual observations for flow pattern transition, positive frictional pressure gradient, and minimum pressure drop. Overall, the results show that the positive frictional pressure gradient approach can provide a better estimation of the onset of liquid loading than the minimum pressure drop approach. Additionally, Tulsa University Fluid Flow Project (TUFFP) unified model (v2016) and OLGA (v2016.2.1) are used to evaluate the average pressure drop, liquid holdup, and flow pattern. Furthermore, the liquid film reversal model, liquid droplet models, and inflection point approach are included in the comparison of the onset of liquid loading with experimental data. The OLGA model predicts the results more precisely than other models. The comparison with the experimental data indicates that inaccurate flow pattern predictions could significantly increase the relative errors in pressure drop and liquid holdup. In addition, the evaluation of OLGA results suggests the need to develop a model for churn flow, as the relative error increases sharply in the churn flow with the model predicting the transition to slug flow.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130890177","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":"Equal Quality Distribution of Two-Phase Fluid by Isokinetic Principle","authors":"Ming Liu, Pengman Niu, X. Zhang, Weibiao Zheng, Zhihui Wang, Dong Wang","doi":"10.2118/209793-pa","DOIUrl":"https://doi.org/10.2118/209793-pa","url":null,"abstract":"\u0000 In thermal recovery of heavy oil, phase separation often occurs when a steam-water stream turns to branches in a junction and distributor, thereby resulting in a significant quality deviation between branches. Although a lot of efforts have been made during the past decades, the problem is still not well solved. Inspired by the principle of the isokinetic probe, this paper builds a new model of distribution. The major change is that the inner space of the main pipe is isolated into fan-shaped isokinetic flow channels, each connecting to a side branch. Flow control devices are installed at the outlet of each branch. Moreover, a swirler is used to convert the incoming flow pattern into a uniform swirling gas core-annular flow before the new isokinetic dividing system. Computational fluid dynamics (CFD) simulations were conducted to reveal the characteristics of gas-liquid two-phase flow within the distributor. The characteristics of both under isokinetic and nonisokinetic flow conditions were analyzed. The most interesting result is that once the uniform swirling gas core-annular flow is formed, liquid film flow becomes very stable and is almost unaffected by the operation deviations from the isokinetic condition, whereas gas flow is much more sensitive to the deviations. The more deviation of isokinetic condition, the more deflection of gas flow or phase separation will take place and the greater quality deviation will be. Air-water two-phase flow experiments were also conducted to verify the CFD results.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122043122","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":"Lessons Learned in Horizontal Well Workovers and Sand Cleanouts, in Cerro Negro Field, Venezuela","authors":"Lenin Perdomo, Giancarlo Molina, Francisco J Mavares, Marian Limpio, Elio Correa, M. Anez","doi":"10.2118/209801-pa","DOIUrl":"https://doi.org/10.2118/209801-pa","url":null,"abstract":"\u0000 The Orinoco Oil Belt in Venezuela contains the largest known deposits of heavy oil in the world, and Cerro Negro is part of the fields in this area. However, the sand production is a major issue which affects the oil production in this field. There are some major issues that stand in the way of the proper cleanout of these wells. These problems include low reservoir pressure, geometry of the wells, and extremely high oil viscosity. Another major problem is the presence of big pieces of progressing cavity pumps (PCP) elastomers, some metallic parts from pressure and temperature sensors configuration, and other metallic parts from previous workover rig operations, encountered during cleanout operations. As a result of these difficulties, some of the past jobs performed in this field were unsuccessful.\u0000 After these unssuccessful jobs, a campaign of recent multiple sand cleanout jobs was planned in the Cerro Negro field. Numerous difficulties arose during these jobs. These issues were largely due to the presence of big pieces of PCP elastomers and metallic parts. An additional issue was the low reservoir pressure. Due to the size of the casing/liner and the horizontal section, the annulus fluid velocity obtained was insufficient. Therefore, several techniques were applied to overcome these problems. One of these methods was to use reverse circulation for the sand cleanout in the 9-5/8-in. slanted casing section, while circulation was still possible to obtain a higher fluid velocity. Afterward, once the circulation was lost, a special stroking pump was used alongside a large string of tubing to store large amounts of sand and debris. This tool was also used to recover pieces of PCP elastomers and other metallic parts. This tool uses a piston pump to create a vacuum effect, and fluid circulation is not needed for the cleanout. Without this innovative stroking pump, it would have been almost impossible to recover these large pieces. This was the first time this innovative tool was used in these types of wells. When the open horizontal 7-in. production zone was reached, coiled tubing (CT) was used with the proper proportion of diesel and nitrogen to obtain enough fluid velocity and the proper equivalent density.\u0000 In the end, when necessary, a smaller reliner was run depending on the information obtained during the analysis of the grain sizes. Some techniques were applied to run the reliner successfully in an old and worn out casing, where the geometry of the well and high doglegs caused difficulties.\u0000 The challenges to complete the cleanout of the well with lost circulation problems included a large annulus area in the highly slanted and horizontal sections, the extremely high oil viscosity, and the presence of large pieces of PCP and metallic parts. These challenges were overcome by using different methods such as the special stroking pump, reverse circulation in the 9.625-in. section, and CT with the proper diesel and nitrogen proportions. Additional","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130626788","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":"The Promotion Effect of Ionic Liquids on Polymer-Driven Recovered Water by Microwave Treatment","authors":"N. Sun, Ding Wang, Qing Quan, Lisha Shen, Huina Sun, Ruiyu Su","doi":"10.2118/209818-pa","DOIUrl":"https://doi.org/10.2118/209818-pa","url":null,"abstract":"\u0000 In view of the difficulties in breaking emulsions and removing oil from polymer-produced water, this study systematically analyzes the promotion effect of anion type, cation type, and concentration of ionic liquid on polymer-driven water produced by microwave treatment. First, when the microwave power is 400 W and the radiation time is 40 seconds, the oil removal rate is only 34.95%. Second, when the anion of the ionic liquid is Br−, the oil/water interfacial tension (IFT) reaches the lowest value. During microwave radiation, the ionic liquid adsorbed on the oil/water interface converts more electromagnetic energy to heat energy owing to dipole polarization and interfacial polarization. In addition, bromine salts have the lowest absolute zeta potential; thus, the electroneutralization effect is the largest. Third, as the length of the cationic alkyl chain of the ionic liquid increases, its synergistic effect with the microwaves first decreases and then increases. Finally, during microwave irradiation, as the concentration of 1-hexadecyl-3-methylimidazole bromide salt increases, the oil removal rate first increases rapidly and then decreases slightly. When the concentration of 1-hexadecyl-3-methylimidazole bromide is 1 mmol/L, the oil removal rate reaches the highest value of 90.31%.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125497761","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":"Deoiling Hydrocyclones: An Experimental Study of Novel Control Schemes","authors":"M. Vallabhan K. G., C. Holden, S. Skogestad","doi":"10.2118/209576-pa","DOIUrl":"https://doi.org/10.2118/209576-pa","url":null,"abstract":"\u0000 Deoiling hydrocyclones are compact, passive devices commonly used for produced-water treatment (PWT) for oil production. The oily water enters the tangential inlet of the hydrocyclone and gets separated such that cleaned water comes out as a water-reject (underflow) stream, and concentrated oil comes out as an oil-reject (overflow) stream. For control purposes, the pressure drop ratio (PDR) across the inlet and the two outlets may be kept constant to maintain separation in the presence of disturbances. However, the PDR control scheme does not effectively reject some disturbances, such as changes in the inlet oil concentration and inlet droplet distribution. This paper proposes three novel control schemes to improve the separation with the aim to limit the oil concentration at the water reject at 30 ppm. The control schemes use concentration measurements from online oil-in-water analyzers at the inlet and water-reject (underflow) outlet. Two control schemes (a feedforward and a feedback/cascade) are used as a supervisory layer to the existing PDR control scheme. The third control scheme directly manipulates the final control element (valve position) to maintain the separation of the hydrocyclones. This paper gives experimental results to validate all three control schemes when subjected to disturbances such as changes in inflow rate, inlet oil concentration, and inlet droplet distribution.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132358658","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}