Day 3 Thu, October 14, 2021最新文献

{"title":"Reservoir Characterization for Uncertainty Analysis and Its Impact on CO2 Injection and Sequestration in a Depleted Offshore Carbonate Gas Field","authors":"Dr. Rabindra Das, P. A. Patil, P. Tiwari, R. Leite, R. Tewari","doi":"10.2118/205706-ms","DOIUrl":"https://doi.org/10.2118/205706-ms","url":null,"abstract":"\u0000 The emerging global climate change policies have necessitated the strategic need for prudent management of produced contaminants and, with cold flaring being no more the best option, Carbon Capture Utilization & Storage (CCUS) technology provides opportunity for development of high CO2 contaminant fields. A typical CO2 sequestration project comprises capturing CO2 by separating from produced hydrocarbons followed by injection of CO2 into deep geological formations for long term storage. While injection ofCO2 may continue over tens of years, the long-term containment needs to be ascertained for thousands of years. Several geological and geophysical factors along with the existingwells need to be evaluated to assess the potential risks for CO2 leakage that maychallenge the long-term containment.\u0000 This study considers a depleted carbonate field located offshore Sarawak as a possible long-term CO2 storage site. Elements that may lead to possible leakage of CO2over time are the existing faults or fractures, development of new fractures/faults during injection, caprock failure due to pressures exceeding fracture pressure during/after injection and possible leakage through existing wells. The risk assessment process includes identification and mapping of faults and fracture networks, mapping of seals, evaluation of seismic anomalies and gas while drilling records, pore-pressure analysis, laboratory experiments for analyzing changes in geomechanical & geochemical rock properties and well integrity of existing wells. All these parameters are cross correlated, and qualitative risk categorization is carried out to determine the robustness of the reservoir for long term CO2 storage.\u0000 The evaluation of available data indicates less frequent faulting occur only towards the flank with no seismic anomalies associated with them. Some seismic anomalies are observed at shallower levels, however their impact on the reservoir and overburden integrity is assessed to be minimum. There are four shale dominated formations mapped in the overburden section, which will act as potential seals. Estimated fracture pressures for the potential seals ranges between 6200-9280 psia for the deepest seal to 2910-4290 psia for the shallowest. Therefore,it is interpreted that if the post injection reservoir pressure is kept below the initial reservoir pressure of 4480 psia, it would not hold any threat to the caprock integrity.Leakage rate riskalong the existing wells was determined based on well log data. Well integrity check of legacywells helped identify two abandoned wells for rigorous remediation to restore their integrity.\u0000 The subsurface risk analysis is critical to ascertain the long-term containment of injectedCO2. The integrated subsurface characterization and well integrity analysis approach adopted in this work can be applied to any other field/reservoir to validate its robustness for long-term CO2 injection and storage.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87776175","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":"Is Artificial Intelligent the Future for AHM? Decision Making Between an Automated Optimisation of ANN Proxy Versus Full Numerical Simulation Optimisation Technique","authors":"Lingies Santhirasekaran, D. Ong, Farren Kaylyn Foo, B. Hasiholan","doi":"10.2118/205808-ms","DOIUrl":"https://doi.org/10.2118/205808-ms","url":null,"abstract":"\u0000 Over the past decades, Assisted History Matching has been the new norm for history matching that leverages the rapid advancement in digital computational performance. Continuous advancements such as parallel computing and GPU accelerates numerical simulation which overcomes the cumbersome experience of working with large fine-scaled model that mainly concerns the simulation time and intervention of engineers. As more interest emerges around artificial intelligence in the optimisation process, this paper explores the Artificial Intelligence algorithm to optimize two proxy modelling techniques: Quadratic Polynomial and Artificial Neural Network proxy model. These techniques are compared with stochastic optimisation method known as Differential Evolution algorithm on their efficiency of optimizing the objective functions, time taken, and knowledge investment needed by engineer, given today's hardware technology.\u0000 This paper starts off by using Latin hypercube experimental design to generate first ensemble of simulation cases to generate proxy models to match the historical cumulative oil and water production by well level. The quality of both proxy modelling techniques is evaluated using R2 coefficient and proxy plot. Proxy models are then further validated by creating real simulation models from variants generated via Monte Carlo Analysis. The history matching quality and practicality were compared between the AI algorithm that runs optimizer on top of existing proxy models, and Differential Evolution algorithm in optimizing the regional porosity and permeability multipliers.\u0000 The ANN proxy model prevailed over quadratic proxies to mimic the numerical reservoir model output with high degree of accuracy. The black-box nature of the ANN proxies limits the interpretability of predicted model when compared quadratic proxies where the formula for the proxy model can be obtained. Quadratic approximations are more flexible, simplistic in nature, and requires less computational cost to be constructed. Despite that, its prediction quality maybe subjected to the degree of non-linearity in the simulation model. The use of AI algorithm vastly reduces the number of full reservoir simulation required to achieve the minimum objective function at a shorter timeframe, which is proved to be the strength of such method. However, AI optimisation is highly susceptible to be trapped in local minimum. This paper proved the superiority of Differential Evolution algorithm over AI, that it may avoid being trapped in local minimum to achieve high degree of prediction accuracy for the history matching given the larger number of iterations required.\u0000 This paper provides a preliminary understanding of optimisation workflow and how to go about each optimisation strategies: quadratic polynomial proxy, ANN proxy, stochastic optimisation, artificial intelligence techniques, and a novel approach of converting proxy predicted variants into real simulation cases to evaluate proxy qu","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87486899","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 Advantages of Having Dedicated Downhole Gauges and Wellhead Meter: A Reservoir Management Perspective from a Massive Tight Gas Reservoir in the Remote Area","authors":"R. Rizkiaputra, Satrio Goesmiyarso, Jufenilamora Nurak, K. Laya, Dimmas Ramadhan, Esterlinda Sinlae, A. Subekti, Anak Agung Gde Iswara Anindyajati","doi":"10.2118/205747-ms","DOIUrl":"https://doi.org/10.2118/205747-ms","url":null,"abstract":"\u0000 Even though the downhole gauges and wellhead meter (wet gas meter) have been invented decades ago, having them installed in every wells are still considered as a luxury for many companies. However, does this view still reasonable for a tight gas reservoir let alone located in a remote area? This study will describe the benefit of having both equipment for reservoir management practice in one of the biggest tight gas reservoirs in Indonesia.\u0000 Generally, reservoir management is an iterative process that incorporates the analysis of reservoir characterization, development plan, implementation, and monitoring. There are many analyses from the reservoir management process that can be performed using above mentioned equipment. Several analyses have been performed, such as: (i) Interference Test and Pressure Transient Analysis (PTA) after well is completed; (ii) Evolution of connected volume since early production until present day using Dynamic Material Balance (DMB); (iii) Flow regime and reservoir properties using Rate Transient Analysis (RTA); and (iv) Reservoir simulation: regular model update and project opportunity identification. In this study, the above-mentioned analyses are performed in one of the massive tight gas reservoir in Indonesia that is located in the remote area.\u0000 Having a complete reservoir surveillance tools such as downhole gauges and wellhead meter on each wells is beneficial for reservoir management practice. Precious subsurface data can be obtained anytime without having to wait for equipment mobilization to location. This is critical for managing tight gas reservoir which usually demands robust subsurface data to reduce its uncertainties. There are several findings based on the above mentioned analyses, such as: (i) The interference test indicates there is reservoir connectivity among the production wells; (ii) The PTA indicates that the reservoir has tight properties, although longer buildup/observation time is still needed to better understand the reservoir characteristics in wider scale; (iii) The DMB analysis can be performed even in daily basis to provide the insight on connected gas initial in place (GIIP) evolution through time, as in this case it still shows an increasing GIIP through time which is suspected due to the transient flow regime on the wells; (iv) The RTA can also be performed in similar fashion, if it is combine with other analyses, this analysis able to provide a multi-scale reservoir properties investigation from near wellbore to far field and flow period observation (boundary observation) through time, as in this case the reservoir properties is tight and flow is still in transient period; (v) It increases robustness of reservoir simulation update since it is supported by many analyses, as such, series of hopper can be confidently presented to management, as in this case a project of well stimulation (Acid Fracturing) has been performed successfully and opportunity of further field development plan c","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87167410","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 Souring Prediction in Deepwater Reservoirs for Field Development Planning","authors":"M. Hanifah, S. R. Panuganti, N. A. Zakaria, N. K. Zaman, R. Tewari","doi":"10.2118/205791-ms","DOIUrl":"https://doi.org/10.2118/205791-ms","url":null,"abstract":"\u0000 A deep-water Field X with two major Reservoirs U and L discovered recently offshore Malaysia is on development for early production. The subsurface plan for the Field X includes water injection. But the presence of sulphate rich seawater can provide a favorable environment for souring activity to take place. This study evaluates the reservoir souring potential for the green Field X as a result of seawater flooding.\u0000 Reservoir souring is the increase of the hydrogen sulfide (H2S) concentration in produced reservoir fluids. As hydrogen sulfide is a highly toxic and corrosive gas, the production of H2S has a huge impact on the safety, infrastructure and facilities of the field. Whether a reservoir is susceptible to souring is dependent on a variety of factors. Some of these include water injection flow rate, temperature of the reservoir, presence of bacterial nutrients and rock minerology.\u0000 Effective prediction of biogenic reservoir souring using computer models is essential when undertaking major technical and economic decisions regarding field development. For H2S concentration calculation PETRONAS utilized in-house stand-alone modeling tool that considers physicochemical hydrodynamics of multiphase flow, heat transfer, substrate propagation and bacterial activity. The simulator looks at bacterial growth both in planktonic and sessile forms. Monod kinetics is applied for the growth of bacteria, leading to the consumption of sulphate and volatile fatty acids which in-turn is linked to H2S generation. Along with H2S propagation, H2S scavenging by rock and H2S partitioning between the various phases is also accounted for. The model can also deal with the effects of lift gas, reinjection of sour produced water, injection of biocide and nitrite. Since the Field X is a green field and historical production data is unavailable, the model is calibrated against the provided field development plan (FDP) data with sensitivity analysis.\u0000 The simulation runs show that the H2S breakthrough occurs before the end of production. The amount of H2S produced indicates that the risk of reservoir souring associated with seawater injection in U and L Reservoirs of the Field X is high. It is recommended to evaluate different reservoir souring preventive measures in combination with mitigative options in terms of chance of success, risks, and cost (CAPEX/OPEX) in the context of the Field X development plan.","PeriodicalId":11052,"journal":{"name":"Day 3 Thu, October 14, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76929596","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}