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Collaborating Authors
Results
Abstract Results of laboratory research conducted in the framework of laboratory program developed jointly by a technology provider and an offshore oil-gas fields operator are presented in this paper. The laboratory program included optimal list of experiments for testing physical and technological properties of the physico-chemical water shut-off agent, resulting in a ready-for-pilot solution at minimum cost and time. The studied water shut-off agent is an emulsion system with nanoparticles (ESN), which is an inverse emulsion augmented by the synergy of natural and artificial surfactants with supercharged silicon dioxide nanoparticles. The ESN consists of three liquid components: sea water, diesel and nanoparticle-based surfactant. One of the main tasks of this research was to study such features of the ESN as selectivity of blocking impact to water-bearing zones and reversibility of blocking effect in the oil-bearing zones of sandstone reservoirs in the Lower Miocene (2950 psi and 91°C) and Late Oligocene (3900 psi and 107°C) hydrocarbon formations. As a basic requirement from the operator, the ESN had to be stable at the said reservoir conditions and compatible with reservoir and process fluids. Besides that, the operator wanted to confirm that the ESN is an easy-to-handle water shut-off agent in the offshore environment, meaning that it can be prepared with ordinary equipment available at the vessel, all components are liquids easily mixed to each other at ambient conditions and ready-to-use composition properties do not change in time within the operation offshore. Thus, the laboratory program was executed in three successive stages, divided based on the experiment conditions: ambient; pressure & temperature; modeled reservoir conditions. In result, the ESN performed as stable and compatible water shut-off agent and met all requirements of the operator. In the series of core floods, conducted on eight sandstone cores of different permeability and saturation, it was confirmed that the ESN selectively and fully blocks water-saturated cores, while the oil-saturated cores permeability decreased slightly with clear tendency to full recovery under the flow of hydrocarbons.
- South America > Brazil (0.68)
- Asia > Vietnam > South China Sea (0.46)
- North America > United States > Oklahoma (0.28)
- (3 more...)
- Phanerozoic > Cenozoic > Paleogene > Oligocene (0.72)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.60)
- North America > United States > California > Los Angeles Basin > Wilmington Field (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 9-2 (0.99)
- Asia > Vietnam > South China Sea > Cuu Long Basin > Block 15-2 > Rang Dong Field (0.99)
- (4 more...)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Abstract In the context of climate change, one way to reduce atmospheric emissions of carbon dioxide is Carbon Capture and Storage (CCS) in both depleted hydrocarbon reservoirs and saline aquifers. The injectivity index is one of the most important parameters to monitor and forecast carbon storage; it determines how rapidly CO2 can be injected, which then determines the rate of storage. This paper verifies the feasibility of a methodology to monitor the well injectivity of a CO2 injector well during its lifetime. In the oil industry, this is based on the acquisition of downhole pressure and temperature during a well test that is interpreted using Pressure Transient Analysis (PTA). Here we investigate if the same techniques could be applied to CO2 injection, considering the complex interaction between CO2, rock, and reservoir fluids. The study was performed running a simplified full-scale reservoir compositional model, representative of a depleted gas reservoir of an Eni CCS project. The so generated bottomhole flowing pressures, were analyzed using PTA to estimate the mechanical skin factor, accounting for the reduction in permeability near the wellbore, which potentially limits the amount of CO2 that can be injected. The work confirmed that the monitoring of the bottom-hole pressure through permanent downhole gauges or even with temporary acquisition memory gauges run-in-hole with a slick-line is crucial for the monitoring in real-time of the well injectivity. Analytical PTA tools provide a sound characterization of the well status: static pressure, permeability-thickness product, permeability, and mechanical skin. Under the assumptions of this study, no significant skin component due to the interaction of the CO2-rock-reservoir fluids was detected; its presence may be apparent in more complex scenarios (i.e., considering induced salt precipitation).
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (3 more...)
Estimation of Surface Production Rates in Electrical Submersible Pump Producing Oil Wells by Numerical Iterative Algorithm-Based Models
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Chandak, Ravi (Cairn Oil & Gas, Vedanta Ltd) | Chauhan, Shailesh (Cairn Oil & Gas, Vedanta Ltd) | Singhal, Joy (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd)
Abstract This paper is an addendum to SPE-200174-MS, which explains the deterministic Approach Towards Well Intervention Candidate Selection & quantification of Parameters in ESP & Jet Pump Wells. The purpose of this paper is to quantify liquid rates in ESP producer wells by estimating the hidden parameter which directly impacts the system production rates. These hidden parameters are the tubing inner wall deposition, deposition inside pumps leading to pump head reduction. These hidden variables make simple well modelling software production rate calculations incorrect. This paper describes facts related to the verification of the output model liquid rates with genuinely observed rates by surface well test units and calibrated multiphase flow meter which makes the overall modelling valid and correct. In ESP wells, the input parameters required by the model is pump intake pressure, pump discharge pressure, pump running frequency and surface THP which are generally available. The models described in SPE-200174-MS for ESP & Jet pump wells can compute 3 variables for 3 set of equations. This model gives surface liquid rates, tubing wall deposition, ESP pump wear (deposition inside pump). Other input parameters required in the model to run the iterations are well water cut, GOR (Gas to oil ratio), productivity index, and reservoir pressure. These models calculate surface production rates for well rates allocation & support in monitoring various wells performance. Its results have been verified by various surface well test units & calibrated multiphase flow meters. There are many advantages of this algorithm such as - Prediction & calibration of MPFMs (Multiphase flow meter data) at well pads, tubing deposition estimation (assists in planning of tubing scraping jobs by slickline unit, Coil tubing roto-jet wellbore cleanout or motor assisted scraper jobs in flowing well), ESP pumps wear estimation (assist in planning ESP wear treatment by chemical soaking/mechanical flushing operations). This paper gives a new approach for ESP wells production rates determination. It mentions various factors which affects the liquid rate of wells. Production restoration candidates are very easily identified using this model. This can be very useful where well testing frequency is less, well pad MPFM is not installed, or where there are frequent issues in MPFM. This work assists in determining various important parameters to monitor oil producer wells with electric submersible pump (ESP). The problems are associated to the fields that contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. It was observed that formation oil to water flooding had adverse mobility ratio and improve sweep efficiency, polymer flooding was adopted. As the Polymer flooding proceeded, polymer breakthrough in producer wells was observed. The major challenges faced in producer wells are polymer & scale depositions. This issue has surfaced in field due to polymer breakthrough in oil producers and mixing of produced polymer concentration in well fluid with scales, wax, or other bivalent ions. Major concerns due to polymer deposition included, fouling of artificial lift system, decrease of well uptime, ESP efficiency decrease. ESP is the major artificial lifts for the field, the surface liquid rate is one of the most important parameters which can address production decrease which may have been caused by any reason. Thus, a necessity was felt to address the issue by empirical based modelling which can quantify the same. The developed models are helpful and determines various surface liquid rate and other critical causal parameters in ESP well.
- North America > United States > Texas (0.68)
- Asia > India > Rajasthan (0.47)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Interfacial Dilational Rheology Between Nitrogen and Aqueous Surfactant Solutions: Implications for Foam-Assisted EOR
Pan, Ziqing (Institute of Energy, Peking University, PR China / Department of Chemical Engineering, Imperial College London, London, United Kingdom) | Trusler, J. P. Martin (Department of Chemical Engineering, Imperial College London, London, United Kingdom) | Zhang, Kaiqiang (Institute of Energy, Peking University, PR China)
Abstract Foam-assisted EOR is a promising technique to meet the ever-growing global energy demand. However, foam is thermodynamically unstable because of large gas-liquid interface. The stability of foam depends largely upon interfacial rheological properties, which represent the resistance capability to disturbance. Most previous studies address limited pressure ranges, not revealing the behavior under subsurface conditions. To fill this gap, we measured the interfacial dilational viscoelasticity of (N2 + SDS (aq)) at various pressures in a high-temperature high-pressure view cell by using the oscillating-drop-profile method. The interfacial elastic and viscous moduli were studied at pressures from ambient pressure up to 26.7 MPa, temperatures of 298 K and 348 K, SDS concentrations below the CMC (0.05 mass% and 0.15 mass%) and above the CMC (0.50 mass%) and oscillating frequencies of 0.125 Hz and 0.0625 Hz, which may correspond to the low-frequency fluctuation expected during the reservoir fluids flow in porous media. The effects of pressure, temperature, SDS concentration and oscillating frequency were examined. Both elastic and viscous moduli decreased with increasing pressure, indicating weaker resistance capability to external disturbance under high-pressure conditions. At concentrations below the CMC, elastic modulus decreased, and viscous modulus increased with increasing temperature, while at concentrations above the CMC, both moduli decreased with increasing temperature. Surfactant solutions with higher concentrations had larger dilational viscoelasticity. However, once the CMC was reached and surfactant micelles were formed in the solution, a significant drop in the interfacial dilational modulus was observed. At concentrations below the CMC, both moduli increased with increasing oscillating frequency, while at concentrations above the CMC, the effect of frequency was insignificant. The expansion and compression of pendant drop during interfacial dilational modulus measurement is closely analogous to foam flow through the heterogeneous porous media. The foam interfacial dilational properties under a variety of pressure, temperature, composition, and oscillating conditions were systematically studied for the first time. The results obtained can help to advance understanding of foams stability, enhance the design of surfactant solutions and provide guide for the implementation of foam-assisted EOR.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Dynamics of Surfactant Imbibition in Unconventional Reservoir Cores
Wei, B. (Southwest Petroleum University, Chengdu, Sichuan, China) | Wang, Y. (Southwest Petroleum University, Chengdu, Sichuan, China / The University of Tulsa, Tulsa, Oklahoma, the United States) | Wang, L. (Southwest Petroleum University, Chengdu, Sichuan, China) | Li, Q. (Southwest Petroleum University, Chengdu, Sichuan, China) | Lu, J. (The University of Tulsa, Tulsa, Oklahoma, the United States) | Tang, J. (United Arab Emirates University, Al Ain, United Arab Emirates)
Abstract Despite the promising results observed from the utilization of interfacial-active additives in enhancing imbibition-based oil recovery from tight reservoirs, the predominant mechanisms governing this process remain inadequately understood. A meticulously designed workflow was implemented to conduct experimental and modeling studies focusing on imbibition tests performed on tight cores utilizing surfactant and microemulsion. The primary objective of this research was to investigate the response of oil recovery to these additives and to develop a robust and reliable model that incorporates the intricate interactions, thereby elucidating the underlying mechanisms. We systematically designed and prepared two imbibition fluids, namely surfactant (AES) and microemulsion (mE), while utilizing brine as a reference fluid. A comprehensive investigation was conducted to analyze the physicochemical properties of these fluids, encompassing phase behavior, density, viscosity, and wettability alteration, with the aim of establishing fundamental knowledge in the field. Imbibition tests were carried out on oil-wet cores to observe the response of oil production and optimize the experimental methodology. Subsequently, we proposed a numerical model that fully coupled the evolution of relative permeability and capillary pressure with the dynamic processes of emulsification, solubilization, and molecular diffusion. All tested fluids exhibited favorable density (1.05-1.07 g/cm) and viscosity (1.0 cp) at the reservoir temperature of 44 °C. AES effectively reduced the oil-water interfacial tension (IFT) to 10 mN/m, while mE achieved an ultralow IFT of 10 mN/m, accompanied by strong emulsification capability and a high solubilization ratio. Both solutions demonstrated the ability to alter the wettability of the rock surface from oil-wet to water-wet, albeit through different mechanisms (adsorption for AES and solubilization for mE). In line with the IFT and phase behavior experiments, imbibition tests on cores revealed that aqueous solutions with interfacial-active additives resulted in significantly higher oil recovery compared to pure water. Notably, the core treated with mE exhibited the highest oil recovery, reaching 36.5% of the original oil in place (OOIP). To further elucidate the observed effects, a modeling study was conducted, considering the aforementioned mechanisms. The results demonstrated the crucial role of emulsification/solubilization in the imbibition process.
- North America > United States > Texas (0.47)
- Asia > Middle East > UAE (0.28)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Smart Liners rely on the limited-entry principle where a number of small holes act to distribute acid along the un-cemented reservoir section. Over the past two years, this technique has become a key method for matrix-acid stimulation of ADNOC's carbonate reservoirs. The objective of this paper is to summarize the learnings from more than 100 deployments and tie together the key elements of the hole spacing design, the stimulation job execution, and the performance monitoring. A software algorithm generates the hole spacing design to honor a predefined acid flow distribution along the drain length. Quantification of the stimulation efficiency is addressed in several ways. First, the baseline well performance is established with production tests covering several months and in some cases accompanied by a pre-stimulation production logging test (PLT). The stimulation job is then analyzed and compared against a wormhole model to derive the transient injectivity improvement versus acid volume pumped. After the stimulation, the stabilized performance is analyzed in terms of production testing and occasionally a pressure buildup survey and a PLT. Results have so far been very encouraging. Smart Liners have been deployed predominantly in oil producers and water injectors but a few implementations have targeted tight gas reservoirs. A typical steady-state productivity gain is 100-150% above the baseline unstimulated well and the technique consistently outperforms conventional matrix-acid stimulation techniques. The post-stimulation PLT's show that the entire wellbore contributes to flow, even in extended-reach wells. The majority of the efficiency improvement seems to occur with an acid coverage of 0.5 bbl/ft but some wells benefit from higher acid dosages. A wormhole model developed specifically for this completion-stimulation method can reproduce the observations and helps guide designs of future stimula0tion jobs by suggesting modifications to the hole spacing, which will improve the performance improvement using less acid volume.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.21)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Al Shaheen Field > Shuaiba Formation (0.99)
- (9 more...)
Predicting Inter-Well Porosity by Comparing the Breakthroughs of Polymeric and Molecular Tracers
Chen, Hsieh (Aramco Americas: Aramco Research Center-Boston) | Yoon, Bora (Aramco Americas: Aramco Research Center-Boston) | Thomas, Gawain (Aramco Americas: Aramco Research Center-Boston) | Poitzsch, Martin E (Aramco Americas: Aramco Research Center-Boston)
Abstract Understanding the porosity distributions across whole reservoirs is crucial in all stages of the exploration and production, such as estimating the original oil/gas in place and recoverable resources, selecting primary/secondary recovery mechanisms, optimizing enhanced recovery methods, etc. Nevertheless, there are no direct methods to probe inter-well porosity beyond near wellbore core analysis or loggings. Here, we propose a new method to directly measure the inter-well porosity using polymeric and molecular inter-well tracers. Specifically, we utilize the transport property of polymers in porous media that the polymers can bypass small pores, i.e., the inaccessible pore volume (IPV), resulting in accelerated breakthrough. In contrast, small molecular tracers will flow through all pores without accelerated breakthrough. By comparing the breakthrough curves of the polymeric and molecular tracers, the inter-well porosity can be measured. We performed reservoir simulations to demonstrate the workflow. In the meantime, we synthesized model low-retention polymer tracer candidates and characterized their IPV in carbonate cores using coreflood experiments. In reservoir simulations, we constructed waterflooding scenarios with both polymeric and molecular water tracers co-injected into injectors and observed their breakthrough curves from producers. Depending on the different porosity distributions between injector-producer pairs, the polymeric tracers can either breakthrough much faster than the molecular tracers, or both polymeric and molecular tracers may breakthrough at a similar time. Ensemble smoother with multiple data assimilation with tracer data (ES-MDA-Tracer) algorithms were then used for history matching and predicting the inter-well porosity. Encouragingly, including both polymeric and molecular tracers resulted in much improved inter-well porosity predictions. In our experimental effort, we synthesized different sizes of the low retention sulfozwitterionic poly(1-vinylimidazole) (PZVIm) polymers that are good candidates for inter-well porosity-sensing tracers. Coreflood experiments co-injecting sulfozwitterionic PZVIm polymer tracers with reference NaBr water tracers in representative carbonate cores showed an IPV of ~10% for the polymers with molecular weight of 46,000 g/mol. Larger polymers may be synthesized to increase the IPV to have more dramatic breakthrough contrasts in the proposed filed applications. In this paper, we presented a novel approach for the direct measurement of inter-well porosity by means of the different transport properties of the polymeric and molecular inter-well tracers, which the polymers are pore-sensitive (with IPV) while the molecular tracers are pore-insensitive. Detailed workflows were demonstrated using reservoir simulations and history matching algorithms. Finally, novel candidate polymers (sulfozwitterionic PZVIm) for this application were experimentally synthesized and verified, which greatly strengthened the validity of our approach.
- Asia > Middle East (0.29)
- North America > United States (0.28)
- North America > United States > Texas > Permian Basin > Midland Basin > Funk Field (0.93)
- North America > United States > Texas > Permian Basin > Central Basin > Cox Field (0.93)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Experimental Study of Surfactant Flooding on Organic Shale with Integrated Characterization
Jiang, T. | El-Sobky, H. F. (ConocoPhillips) | Bonnie, R. J. M. (ConocoPhillips) | Bone, R. (ConocoPhillips) | Beveridge, W. (ConocoPhillips) | Carman, P. S. (ConocoPhillips) | Jweda, J. (ConocoPhillips) | Long, H. (ConocoPhillips) | MacMillan, A. (ConocoPhillips) | Nguyen, V. H. (ConocoPhillips) | Warren, L. (ConocoPhillips) | McLin, K. S. (ConocoPhillips)
Abstract Enhanced oil recovery from organic shale reservoirs has increasingly gained interest from oil and gas industry in recent years. The recovery factor of organic shale oil production depends on formation wettability and pore fluid trapping mechanisms. A combination of hydraulic fracturing and surfactant flooding can be used to reduce oil trapping and increase oil recovery by reducing the interfacial tension and decreasing oil wettability. A novel experimental workflow has been developed based on fluid flow monitoring and NMR characterization to study the effect of surfactant flooding on organic-rich shales in the lab. Two blends of surfactants (cationic and nonionic) were carefully selected from prior contact angle (CA) and interfacial tension (IFT) measurements for the surfactant flooding tests. Micro-CT screening was used to select fracture-free samples for these tests. Prior to flooding we acquired nuclear magnetic resonance (NMR) T1-T2 measurements on as-received core samples to establish base-line water and oil saturations. Next, the core samples were pressure-saturated with crude oil at reservoir pressure and temperature, and we continued the aging process for a given time. Following aging, core samples were flooded using continuous crude oil injection from one end of the core sample whilst monitoring fluid flow rate, temperature, and pressure. Robust initial effective oil permeability was computed when the flow system reached steady state. Next, fracturing fluids -with and without surfactants- were injected from the opposite end of the core plugs to simulate the forced imbibition of fracturing fluid along with hydraulic fracturing in real field operations. Finally, the injection of crude oil was resumed from the original end of the core sample to establish the flowback effective oil permeability after hydraulic fracturing and surfactant flooding. We acquired NMR data after each fluid injection step to monitor fluid saturation and wettability changes in the core samples. Additionally, porosity and saturation measurements, X-ray diffraction (XRD), rock-eval pyrolysis and mercury injection capillary pressure (MICP) tests are performed to characterize fluid distribution, mineralogy and pore throat sizes of the rock samples. The results of fracturing fluid injection in all core samples clearly indicate that the water from the fracturing fluid does partially displace the crude oil in the core, effectively making this oil recoverable. Samples injected with the blend of cationic surfactants show less than 3% incremental recovery over samples with no surfactant injection. The flowback effective oil permeabilities of all core samples are much lower than the initial effective oil permeabilities prior to fracturing fluid injection. This observation is corroborated by the differences in MICP results before and after fracturing fluid injection, showing smaller pore throat sizes after fracturing fluid injection. Our novel workflow has successfully characterized the impact of surfactant flooding on organic-rich shale samples in lab-scale tests. and can be used for screening of surfactant enhanced oil recovery before running more expensive field trials.
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Application of the Producer-Based Capacitance Resistance Model to Undersaturated Oil Reservoirs in Primary Recovery
Parra, José E. (Universidad Nacional Autónoma de México (UNAM) (Corresponding author)) | Samaniego-V, Fernando (Universidad Nacional Autónoma de México (UNAM)) | Lake, Larry W. (The University of Texas at Austin)
The University of Texas at Austin Summary We investigated the application and usefulness of the producer-based representation of the capacitance resistance model (CRM) to characterize single and multiwell undersaturated oil reservoirs during primary recovery. The CRM is a physics-based, data-driven method that has been amply used to model reservoirs under different recovery stages, particularly during flooding processes. However, there have been very few applications to primary recovery. The previous work on primary recovery used the rate and bottomhole pressure (BHP) data to calculate the time constant or storage capacity, and the productivity index (PI) associated with each production well. Here, we incorporate popular productivity models in CRM, making the results comparable with those from pressure transient analysis (PTA) or rate transient analysis (RTA). We also investigate various topics that have not been discussed or that deserve a further explanation to include CRM in the reservoir engineering toolbox. These comprise constant and variable rate wells, transient flow, well location, well geometry, anisotropy, and different types of reservoir heterogeneity. CRM is systematically compared and validated against analytical and numerical models of single and multiwell reservoirs. We also use it to characterize flow in a real oil reservoir. Our results demonstrate that CRM can provide important parameters for reservoir characterization using BHP and rate data acquired from routine production operations, that is, without the need to shut in wells or perform dedicated tests. It yields reasonable estimates of flow resistance properties that depend on reservoir geology, petrophysics, and well condition. It can also be applied during successive time intervals to assess changes in well-reservoir properties, such as drainage radius or the PI, an indication of well damage. Most importantly, we show that for several well-reservoir cases with multiple complexities, CRM can accurately capture the reservoir size, or the drainage pore volume (PV) associated with each well in developed fields, which enables the calculation of average pressure and helps assess interwell communication and opportunities for infill drilling. Introduction The CRM combines reduced-physics and data-driven methods for reservoir characterization and modeling. The modern CRM is an analytical approach (Yousef et al. 2006, 2009), as opposed to the experimental models developed much earlier (Bruce 1943; Wahl et al. 1962). It is derived from a coupling of material balance (a continuity equation) and a rate equation.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Rapid Simulation and Optimization of Geological CO2 Sequestration Using Coarse Grid Network Model
Aslam, Billal (King Abdullah University of Science and Technology) | Yan, Bicheng (King Abdullah University of Science and Technology) | Tariq, Zeeshan (King Abdullah University of Science and Technology) | Krogstad, Stein (SINTEF Digital) | Lie, Knut-Andreas (SINTEF Digital)
Abstract Large-scale CO2 injection for geo-sequestration in deep saline aquifers can significantly increase reservoir pressure, which, if not appropriately managed, can lead to potential environmental risk. Brine extraction from the aquifer has been proposed as a method to control the reservoir pressure and increase storage capacity. However, iterative optimization of the well controls for this scenario using high-resolution dynamic simulation models can be computationally expensive. In this paper, we demonstrate the application of a so-called coarse–grid network model (CGNet) as a reduced-order model for efficient simulation and optimization of CO2 sequestration with brine extraction. As a proxy, CGNet is configured by aggressively coarsening the fine-scale grid and then tuning the parameters of the associated simulation graph (transmissibility, pore volumes, well indices, and relative permeability endpoints) by minimizing the mismatch of well-response data (rates, bottom-hole pressure) and saturation distribution from the fine-scale model. Calibration and optimization procedures are automated using gradient-based optimization methods that leverage automatic differentiation capabilities in the reservoir simulator in the same way backpropagation methods are used in training neural networks. Once calibrated, CGNet is employed for well-control optimization. Validation with the fine-scale model shows that CGNet closely matches the optimized net-present value (NPV). Numerical examples using the Johansen model, available as a public dataset, shows that the optimization can be accelerated up to seven times using CGNet compared with a fine-scale model. (Using a compiled language will likely result in significantly larger speedups as small models suffer from a disproportionately high computational overhead when executed in MATLAB.) This study implies that a reduced-order model such as CGNet can be a powerful data-driven tool for faster evaluation of CO2 geo-sequestration simulation, combined with proper reservoir monitoring program.
- Europe (0.93)
- North America > United States (0.93)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)