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Collaborating Authors
Results
The Impact of Autonomous Inflow Control Valve on Improved Oil Recovery in a Thin-Oil-Rim Reservoir
Taghavi, Soheila (University of South-Eastern Norway / InflowControl AS (Corresponding author)) | Aakre, Haavard (InflowControl AS) | Tahami, Seyed Amin (University of South-Eastern Norway) | Moldestad, Britt M. E. (University of South-Eastern Norway)
Summary Oil production from thin-oil-rim fields can be challenging as such fields are prone to gas coning. Excessive gas production from these fields results in poor production and recovery. Hence, these resources require advanced recovery methods to improve the oil recovery. One of the recovery methods that is widely used today is advanced inflow control technology such as autonomous inflow control valve (AICV). AICV restricts the inflow of gas in the zones where breakthrough occurs and may consequently improve the recovery from thin-oil-rim fields. This paper presents a performance analysis of AICVs, passive inflow control devices (ICDs), and sand screens based on the results from experiments and simulations. Single- and multiphase-flow experiments are performed with light oil, gas, and water at typical Troll field reservoir conditions (RCs). The obtained data from the experiments are the differential pressure across the device vs. the volume flow rate for the different phases. The results from the experiments confirm the significantly better ability of the AICV to restrict the production of gas, especially at higher gas volume fractions (GVFs). Near-well oil production from a thin-oil-rim field considering sand screens, AICV, and ICD completion is modeled. In this study, the simulation model is developed using the CMG simulator/STARS module. Completion of the well with AICVs reduces the cumulative gas production by 22.5% and 26.7% compared with ICDs and sand screens, respectively. The results also show that AICVs increase the cumulative oil production by 48.7% compared with using ICDs and sand screens. The simulation results confirm that the well completed with AICVs produces at a beneficial gas/oil ratio (GOR) for a longer time compared with the cases with ICDs and sand screens. The novelty of this work is the multiphase experiments of a new AICV and the implementation of the data in the simulator. A workflow for the simulation of AICV/ICD is proposed. The simulated results, which are based on the proposed workflow, agree with the experimental AICV performance results. As it is demonstrated in this work, deploying AICV in the most challenging light oil reservoirs with high GOR can be beneficial with respect to increased production and recovery.
- Asia (1.00)
- North America > United States > Wyoming > Carbon County (0.65)
- Europe > Norway > North Sea > Northern North Sea (0.49)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- South America > Colombia > Putumayo Department > Putumayo Basin > Acordionero Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Vรฅle Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > A2 North Heimdal T60 Formation (0.99)
- (36 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Experimental Investigation of Solids Production Mechanisms in a Hydraulic Screen-Through Fracturing Well in a Loose Reservoir and Its Control
Dilimulati, Saifula (School of Petroleum Engineering, China University of Petroleum (East China) / Research Institute of Engineering, Sinopec Northwest Branch Company) | Dong, Changyin (School of Petroleum Engineering, China University of Petroleum (East China) / Key Laboratory of Unconventional Oil & Gas Development, Ministry of Education (Corresponding author)) | Zhan, Xinjie (School of Petroleum Engineering, China University of Petroleum (East China) / Key Laboratory of Unconventional Oil & Gas Development, Ministry of Education) | Li, Jingwei (School of Petroleum Engineering, China University of Petroleum (East China) / Key Laboratory of Unconventional Oil & Gas Development, Ministry of Education) | Cui, Guoliang (Engineering Technology Branch, CNOOC Energy Development Co., Ltd.) | Liu, Quangang (Engineering Technology Branch, CNOOC Energy Development Co., Ltd.) | Bai, Haobin (School of Petroleum Engineering, China University of Petroleum (East China) / Key Laboratory of Unconventional Oil & Gas Development, Ministry of Education)
Summary Successful cases of hydraulic screen-through fracturing (HSTF) in the Bohai oil field highlight the possibility that hydraulic fracturing can be an alternative method for enhancing the productivity of loose reservoirs. However, a portion of the HSTF wells in the Bohai oil field suffer from severe solids production, meaning that proppants and stratum sands are produced in the wellbore during production and cause wellbore plugging and ensuing debilitation of productivity. In this study, fluid flow amid the stratum, fracture, and HSTF well is simulated experimentally, and pressure drop, flow rate of the fracture, and stratum are monitored to investigate mechanisms and influencing factors of solids production from HSTF wells. Perspectives on solids control optimization are put forward for the Bohai oil field. Results indicate that the formation of an erosion cavity on lip-sealing in fracture and a dominant fluid channel near the wellbore in the stratum are two main mechanisms of solids production. The higher the flow rate and fluid viscosity are, the more severe solids production can be. For the Bohai oil field, with 725-psi-strength resin-coated proppant, the minimum proportion of resin-coated proppant in fractures to prevent solids production can be reduced from the previous 65% to 30%. With 1,073-psi-strength resin-coated proppant, it can be further reduced to 20%. Reducing the proportion of resin-coated proppant can help optimize the conductivity of fractures. This study aims to provide preliminary insight on solving the solids production problem of an HSTF well, thus enhancing the applicability of hydraulic stimulation in loose reservoirs.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Mineral > Silicate (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Asia > Middle East > Bahrain > Awali Field (0.99)
- North America > United States > Louisiana > China Field (0.97)
- Asia > Azerbaijan > Aran Region > Middle Caspian Basin > Yevlakh-Aghjabady Depression > Muradkhanli-Jafarli-Zardab Block > Jafarli Field > J-2 Well (0.89)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Well J-1 (0.89)
Quantitative Analysis of Hydraulic Fracturing Test Site 2 Completion Designs Using Crosswell Strain Measurement
Mjehovich, Joseph (IFDATA LLC (Corresponding author)) | Srinivasan, Aishwarya (Department of Petroleum Engineering, Texas A&M University) | Wang, Wen (IFDATA LLC) | Wu, Kan (Department of Petroleum Engineering, Texas A&M University) | Jin, Ge (Department of Geophysics, Colorado School of Mines)
Summary The implementation of effective completion design configurations during hydraulic stimulation is critical for the economic development of unconventional reservoirs. Low-frequency distributed acoustic sensing (LF-DAS)-based crosswell strain measurement is an advanced monitoring technique used to diagnose completion design efficiency but has been primarily restricted to qualitative analysis. In this study, we apply our novel Green-function based inversion algorithm to calculate fracture geometry (i.e., width) using the Department of Energy sponsored Hydraulic Fracturing Test Site 2 (HFTS-2) data set. The adopted algorithm relies on a 3D displacement discontinuity method to construct geomechanical models inverting linear elastic strain to hydraulic fracture widths. We use the inversion algorithm to calculate dynamic fracture widths using LF-DAS data recorded at two horizontal monitoring wells with permanent optical fiber installations. The inverted fracture widths at the monitoring wells from more than 100 hydraulic fracturing stages are used to diagnose the efficiency of eight unique completion designs implemented across three fracturing wells. We develop several metrics to evaluate completion design efficiency including the evenness of fracture widths at the monitoring wells, fracture density (i.e., number of fracture hits per foot), and fracture-width-density (i.e., fracture width/stage length). We observe a significant impact on completion efficiency with varying degrees of limited entry, tapered configurations, and stage length designs. Results indicate improved hydraulic stimulation is achieved with the implementation of limited-entry designs for extended stage lengths (ESLs), but no observable trend for normal stage lengths (NSLs). Tapered configurations significantly improve efficiency for ESLs but indicate little impact on normal-length designs. Reducing the space between perforation clusters (PCs) is determined to negatively impact design performance. Additionally, our quantitative analysis describes the impact of the nearby depletion zone on completion design efficiency. The methodology developed in this study provides operators with another level of quantitative information to optimize hydraulic fracturing treatments and reduce costs associated with the development of unconventional wells.
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.94)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.94)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary The centrifuge experiment is used to measure capillary pressure in core plugs by forced displacement (imbibition or drainage): Strong gravitational forces (imposed by rotation) displace fluid held in place by capillary forces. This setup is also used to measure and establish residual saturation, the saturation where a fluid loses connectivity and can no longer flow. Obtaining this saturation is challenging as the capillary end effect causing outlet fluid accumulation theoretically only vanishes at infinite rotation speed. First, we derive a novel โintercept methodโ to estimate residual saturation with a centrifuge: Plotting steady-state average saturation data against inverse squared rotation speed gives a straight line at high speeds where the intercept equals the residual saturation. The linear behavior starts once the core saturation profile contains the residual saturation. The result is theoretically valid for all input parameters and functions, derived assuming uniform gravity along the core at a given speed. Then the saturation profile near the outlet is invariant and compresses at a higher speed. The method was, however, demonstrated numerically to be highly accurate even for extremely nonuniform gravity: The saturation data are linear and the correct residual saturation value is estimated. This is because when the residual saturation enters, most of the end effect profile is located in a narrow part of the core and thus uniformly compressed. Several experimental and numerical data sets validated the method. Second, an analytical solution (using all relevant input) is derived for transient production toward equilibrium after the rotation speed is increased starting from an arbitrary initial state. For this result, we assume the outlet (or initial) profile compresses also transiently. The displacing and displaced regions have fixed mobilities but occupy different lengths with time. Time as a function of production has a linear term and logarithmic term (dominating late time behavior). Production rate can thus be constant most of the time or gradually reducing, resulting in very distinct profiles. The correlation could fit experimental data well and confirmed the possible profile shapes. A time scale was derived analytically that scales all production curves to end (99.5% production) at same scaled time. The solution predicted similar time scales and trends in time scale with rotation speed and viscosity as numerical simulations. Numerical simulations indicated that the saturations near the residual saturation traveled slowly, which caused production to tail and span 5 log units of time (the analytical solution predicted 2โ3). The correlation better matched low-speed data where the residual saturation had not entered.
- Europe (1.00)
- North America > United States (0.93)
Surfactant Enhanced Oil Recovery Improves Oil Recovery in a Depleted Eagle Ford Unconventional Well: A Case Study
Ataceri, I. Z. (Texas A&M University) | Saputra, I. W. R. (Texas A&M University) | Bagareddy, A. R. (Texas A&M University) | Elkady, M. H. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Haddix, G. W. (Third Wave Production LLC (Corresponding author)) | Brock, V. A. (Third Wave Production LLC) | Raney, K. H. (Third Wave Production LLC) | Strickland, C. W. (Third Wave Production LLC) | Morris, G. R. (Auterra Operating LLC)
Summary A simple huff โnโ puff (HnP) injection and flowback using a nonionic surfactant solution to drive enhanced oil recovery (EOR) in a depleted Eagle Ford โblack oilโ unconventional well has been executed and analyzed. The pilot injection was performed in December 2020, with pressures below the estimated fracture gradient. More than 12,300 bbl of surfactant solution were injected into the 6,000-ft lateral. In January 2021, the well was put back on production with oil and water flow rate data being gathered and samples collected. Within 3 months of the well being put back onto production after surfactant stimulation, the well produced at oil rates over five times what it had produced before stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the prestimulation rates. Using a long-term hyperbolic fit to historical data as the โmost likelyโ production scenario in the absence of stimulation as a โbaseline,โ incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing West Texas Intermediate (i.e., WTI) prices at the time of production and the known costs of the pilot result in project payout time less than 1 year and project internal rate of return in excess of 80%, with only incremental production to date. These results prove the potential for technoeconomic viability of HnP EOR techniques using surfactants for wettability alteration in depleted unconventional oil wells. The well was chosen from a portfolio of unconventional Eagle Ford black oil window wells that were completed in the 2012โ2014 time frame. The goal of the test was to demonstrate successful application of laboratory work to the field and economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on laboratory work completed on oil and brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical and economic objectives of the field test were to (1) inject surfactant solution to contact sufficient matrix surface area that measurable and economically attractive amounts of oil could be mobilized, (2) measure the amount of surfactant produced in the flowback stream to determine the amount of surfactant retained in the reservoir, and (3) prove the concept of using wettability alteration in conjunction with residual well energy in a depleted well to achieve economically attractive incremental recovery. Surfactant selection was completed in the laboratory using oil and brine gathered from potential target wells, and rock from nearby wells completed in the same strata. Several surfactant formulations were tested, and a final nonionic formulation was chosen on the basis of favorable wettability alteration and improved spontaneous imbibition recovery. The design for the pilot relied on rules of thumb derived from unconventional completion parameters. Rates, pressures, and injectant composition were carefully controlled for the single-day โbullheadโ injection. Soak time between injection and post-stimulation restart of production was inferred from laboratory-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates were monitored since production restart. Flowback samples were analyzed for total dissolved solids (TDS), ions, and surfactant concentration.
- Geology > Mineral (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (5 more...)
Assessing Geological Deformation Across Spatial and Temporal Scales Using Distributed Fiber Optic Sensing
Busetti, S. (Aramco Americas: Aramco Research CenterโHouston (Corresponding author)) | Kazei, V. (Aramco Americas: Aramco Research CenterโHouston) | Merry, H. (Aramco Americas: Aramco Research CenterโHouston)
Summary This work presents a conceptual framework for assessing geological deformation using distributed fiber-optic sensing (DFOS) that is applicable to several common sources of strain encountered during the reservoir life cycle. Common applications include strain associated with seismic and aseismic fault motion, natural and hydraulic fracture dilation and closure, and poroelastic strain evolution during injection and production. We briefly review common geological sources of strain observed in reservoir settings, then discuss the main fiber-based techniques for recording strain with attention to key deformation characteristics at different spatial and temporal resolutions. The relationships between common acquisition parameters, such as spatial resolution, data sampling rate, ability to measure relative and absolute strain, and a priori knowledge of geological strain including geomechanical models, and the availability of baseline measurements are discussed. Finally, a few examples are shown from experimental studies at the Aramco Research Center in Houston, Texas, USA. The facilities host a shallow vertical well instrumented with fiber as well as a surface fiber network embedded in a cement pad. We highlight several data sets acquired using Brillouin and Rayleigh frequency shift (BFS and RFS), low-frequency distributed acoustic sensing (LF-DAS), and DAS interrogation techniques, with a focus on concepts helpful for interpreting field strain. Using these insights as a conceptual framework for assessing geological deformation leads to more informed decisions when planning DFOS acquisitions and interpreting associated strain data.
- Asia > Middle East > Saudi Arabia (1.00)
- Africa > Middle East > Egypt (1.00)
- Asia > Middle East > Yemen (0.93)
- (2 more...)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.48)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- North America > Canada > Alberta > Newell Field > Altex Et Al Newell 3-20-17-14 Well (0.97)
- (3 more...)
A Deep-Learning-Based Graph Neural Network-Long-Short-Term Memory Model for Reservoir Simulation and Optimization With Varying Well Controls
Huang, Hu (China University of Geosciences) | Gong, Bin (China University of Geosciences (Corresponding author)) | Sun, Wenyue (China University of Petroleum (East China))
China University of Petroleum (East China) Summary A new deep-learning- based surrogate model is developed and applied for predicting dynamic oil rate and water rate with different well controls. The surrogate model is based on the graph neural networks (GNNs) and long-short- term memory (LSTM) techniques. The GNN models are used to characterize the connections of injector-producer pairs and producer-producer pairs, while an LSTM structure is developed to simulate the evolution of the constructed GNN models over time. In this way, we use geological attributes at wells and well controls with different times as input data. The oil rates and water rates at different times are generated. In this study, the GNN-LSTM surrogate model is applied to a high dimensional oil-gas- water field case with flow driven by 189 wells (i.e., 96 producers and 93 injectors) operating under time-varying control specifications. A total of 500 high-fidelity training simulations are performed in the offline stage, out of which 450 simulations are used for training the GNN-LSTM surrogate model, which takes about 150 minutes on an RTX2060 GPU. The trained model is then used to provide production forecasts under various well control scenarios, which are shown to be consistent with those obtained from the high-fidelity simulations (e.g., around 4.8% and 4.3% average relative errors for water production rates and oil production rates, respectively). The online computations from our GNN-LSTM model take about 0.3 seconds per run, achieving a speedup of over a factor of 1,000 relative to the high-fidelity simulations, which takes about 363 seconds per run. Overall, this model is shown to provide reliable and fast predictions of oil rates and water rates with a large level of perturbations in the well controls. Finally, the proposed GNN-LSTM model, in conjunction with the particle swarm optimization (PSO) technique, is applied to optimize the field oil production by varying the well control schedule of all injectors. Due to the significant speedup and high accuracy of the proposed surrogate model, the improved well-control strategies can be efficiently obtained. Introduction Reliable production forecasting is very important for reservoir management and production optimization. Reservoir simulation is a key technique that has been widely applied to simulate subsurface flow behaviors and provide production forecasting. However, due to the complex subsurface geologies, multiphase flow physics, and heterogeneous rock properties, detailed geo-cellular models with over millions of grid blocks are often needed in reservoir simulation, which entails very high computational costs.
- North America > United States (0.93)
- Europe (0.92)
- Asia (0.68)
Summary Understanding gas dynamics in mud is essential for planning well control operations, improving the reliability of riser gas handling procedures, and optimizing drilling techniques, such as the pressurized mud cap drilling (PMCD) method. However, gas rise behavior in mud is not fully understood due to the inability to create an experimental setup that approximates gas migration at full-scale annular conditions. As a result, there is a discrepancy between the gas migration velocities observed in the field as compared to analytical estimates. This study bridges this gap by using distributed fiber-optic sensors (DFOS) for in-situ monitoring and analysis of gas dynamics in mud at the well scale. DFOS offers a paradigm shift for monitoring applications by providing real-time measurements along the entire length of the installed fiber at high spatial and temporal resolution. Thus, it can enable in-situ monitoring of the dynamic events in the entire wellbore, which may not be fully captured using discrete gauges. This study is the first well-scale investigation of gas migration dynamics in oil-based mud with solids, using optical fiber-based distributed acoustic sensing (DAS) and distributed temperature sensing (DTS). Four multiphase flow experiments conducted in a 5,163-ft-deep wellbore with oil-based mud and nitrogen at different gas injection rates and bottomhole pressure conditions are analyzed. The presence of solids in the mud increased the background noise in the acquired DFOS measurements, thereby necessitating the development and deployment of novel time- and frequency-domain signal processing techniques to clearly visualize the gas signature and minimize the background noise. Gas rise velocities estimated independently using DAS and DTS showed good agreement with the gas velocity estimated using downhole pressure gauges.
- North America > United States > Texas (0.68)
- Europe (0.68)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.93)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.51)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.35)
Oil-Water Flowing Experiments and Water-Cut Range Classification Approach Using Distributed Acoustic Sensing
Liu, Junrong (School of Petroleum Engineering, China University of Petroleum (East China) (Corresponding author)) | Han, Yanhui (Research Institute of Petroleum Engineering Technology, Sinopec Shengli Oilfield Company) | Jia, Qingsheng (Research Institute of Petroleum Engineering Technology, Sinopec Shengli Oilfield Company) | Zhang, Lei (Research Institute of Petroleum Engineering Technology, Sinopec Shengli Oilfield Company) | Liu, Ming (Research Institute of Petroleum Engineering Technology, Sinopec Shengli Oilfield Company) | Li, Zhigang (School of Petroleum Engineering, China University of Petroleum (East China) / National Engineering Research Center of Oil & Gas Drilling and Completion Technology)
Research Institute of Petroleum Engineering Technology, Sinopec Shengli Oilfield Company Summary The accurate measurement of dynamic water cut is of great interest for analyzing reservoir performance and optimizing oilwell production. Downhole water-cut measurement is a very challenging work. Moreover, the surface-measured water cut is a comprehensive indicator of commingled producing well and it is difficult to use this parameter to deduce the downhole water cut of each contributing layer. In this paper, we propose to use distributed fiberoptic acoustic sensing (DAS) technology for the classification of water-cut range. DAS can dynamically monitor the entire wellbore by "listening" to the acoustic signals during flow. A large number of laboratory experimental data from DAS have been collected and analyzed using wavelet time scattering transform and short-time Fourier transform (STFT). The extracted low-variance scattering feature, short time-frequency feature, and fusion feature (combination of two extracted features) were learned with backpropagation (BP) neural network, decision tree (DT), and random forest (RF) algorithm. Then, a classification method of water-cut range in oil-water flow was established with machine learning. Field DAS data were collected from two oil wells to verify the effectiveness of the proposed method. The classification accuracies for the vertical well (Well A) are 92.4% and 87.4% by DT and RF model, respectively. For the horizontal well (Well B), the average classification accuracy exceeds 90% for all three methods. Water shutoff measure was conducted in Well B, and an obvious water decrease was realized. The result shows that the fusion feature overweighs single feature in machine learning with DAS data. This study provides a novel way to identify downhole water-cut range and detect water entry location in horizontal, vertical, and deviated oil-producing wells. Introduction Both temporal and spatial information on water flow rate from an oil well perforated through multilayers is important for predicting oil production rates, tracking reservoir performance, and optimizing oilwell production (Alkhalaf et al. 2019).
- Europe (1.00)
- Asia > China (0.68)
- Asia > Middle East > UAE (0.46)
- North America > United States > Texas (0.28)
- Geology > Rock Type (0.68)
- Geology > Geological Subdiscipline (0.67)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (24 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Bi-Objective Optimization of Subsurface CO2 Storage with Nonlinear Constraints Using Sequential Quadratic Programming with Stochastic Gradients
Nguyen, Quang Minh (The University of Tulsa) | Onur, Mustafa (The University of Tulsa (Corresponding author)) | Alpak, Faruk Omer (Shell International Exploration & Production Inc)
Summary This study focuses on carbon capture, utilization, and sequestration (CCUS) via the means of nonlinearly constrained production optimization workflow for a CO2-enhanced oil recovery (EOR) process, in which both the net present value (NPV) and the net present carbon tax credits (NPCTC) are bi-objectively maximized, with the emphasis on the consideration of injection bottomhole pressure (IBHP) constraints on the injectors, in addition to field liquid production rate (FLPR) and field water production rate (FWPR), to ensure the integrity of the formation and to prevent any potential damage during the life cycle injection/production process. The main optimization framework used in this work is a lexicographic method based on the line-search sequential quadratic programming (LS-SQP) coupled with stochastic simplex approximate gradients (StoSAG). We demonstrate the performance of the optimization algorithm and results in a field-scale realistic problem, simulated using a commercial compositional reservoir simulator. Results show that the workflow can solve the single-objective and bi-objective optimization problems computationally efficiently and effectively, especially in handling and honoring nonlinear state constraints imposed onto the problem. Various numerical settings have been experimented with to estimate the Pareto front for the bi-objective optimization problem, showing the trade-off between the two objectives of NPV and NPCTC. We also perform a single-objective optimization on the total life cycle cash flow, which is the aggregated quantity of NPV and NPCTC, and quantify the results to further emphasize the necessity of performing bi-objective production optimization, especially when used in conjunction with commercial flow simulators that lack the capability of computing adjoint-based gradients.
- Europe (1.00)
- North America > United States > Oklahoma (0.46)
- North America > United States > Texas (0.28)
- Asia > Middle East > UAE (0.28)