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Results
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...)
Numerical Simulation Study of Relative Permeability Hysteresis in a Fractured Carbonate Reservoir Subjected to Water-Alternating-Gas Injection (WAG-CO2)
Menezes, D. E. S. (Center for Energy and Petroleum Studies, University of Campinas, Campinas, SP, Brazil) | Botechia, V. E. (Center for Energy and Petroleum Studies, University of Campinas, Campinas, SP, Brazil) | Santos, S. M. G. (Center for Energy and Petroleum Studies, University of Campinas, Campinas, SP, Brazil) | Skauge, A. (Institute of GeoEnergy Engineering, Heriot-Watt University, Edinburgh, UK / Energy Research Norway, Bergen, Norway) | Schiozer, D. J. (Center for Energy and Petroleum Studies, University of Campinas, Campinas, SP, Brazil)
Abstract The hysteresis phenomenon in relative permeability curves is an important aspect when modeling WAG- CO2 processes. Although experimentally validated, this phenomenon is often overlooked in numerical studies. Furthermore, the impact of hysteresis on oil recovery is a complex issue, which may hinder or contribute to the sweep efficiency. This work evaluates different hysteresis scenarios for a comprehensive analysis of this phenomenon in a synthetic fractured carbonate field analogous to a pre-salt field in Brazil (UNISIM-II-D). The hysteresis is applied in two different scenarios: (i) in low-permeability porous medium (LK); (ii) also included to a lesser extent in high-permeability layers (LSK). The work initially presents sensitivity analyses based on attributes of the Larsen-Skauge WAG hysteresis model. The results reveal that the impact of hysteresis on oil recovery differ for different production strategies. The sensitivity profile of each hysteresis attribute also differs notably between the two assessed hysteresis scenarios, with the effect being more pronounced in the LSK scenario, even at low attribute values. Then, a nominal optimization of reservoir development and management variables is presented for each hysteresis scenario and for the scenario with no hysteresis. We verified that the application of an optimized solution in a non-corresponding scenario may compromise economic and production indicators. The results demonstrate the importance of incorporating the hysteresis phenomenon into models used in life cycle optimization processes (LCO), as the field should be operated differently when hysteresis is identified as a real phenomenon. Finally, the impact of hysteresis on an ensemble of 197 models under uncertainty was evaluated considering two approaches: (i) hysteresis scenario as uncertainty; (ii) values of the Larsen-Skauge's hysteresis model as uncertainty. In both cases, the NPV risk curves were similar to the original one, in which hysteresis was not included as uncertainty. However, changes were observed for some production indicators and the impact may be more significant for different cases. The results also revealed that different hysteresis scenarios can impact the NPV and production indicators differently when applied to an ensemble of reservoir scenarios, resulting in either positive or negative trends. In this benchmark, hysteresis in low-permeability porous medium at immiscible conditions tend to cause a slight decrease of oil recovery, while hysteresis in Super-k promoted a better mobility control of gas and water in these layers, favoring the production and economic outcomes. Hence, this numerical study provides an extensive analysis of the effects of different hysteresis scenarios on applications that have not been previously explored, such as hysteresis in high- permeability layers, in reservoir life-cycle optimizations, and in a probabilistic approach.
- South America > Brazil (1.00)
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > Texas (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- Geology > Rock Type > Sedimentary Rock (0.93)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.50)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (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)
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...)
Abstract Foam flooding is positioned to be one of the promising oil recovery techniques to keep up with the continuously increasing global energy demand. Due to their low sensitivity to gravity and permeability heterogeneities that boost sweep efficiency, foams are preferred injection fluids over water or gas. However, this method is not frequently used because of the thermodynamic instability of foams. Therefore, a stable additive that maintains the foam properties in reservoir conditions is needed. Due to its promising properties, such as interfacial tension reduction, increased viscosity and density, wettability modification, and others, nanoparticles have gained attention for their various applications in oil recovery. Even though a number of factors have been studied in the past in relation to increasing foam stability with nanoparticles, the ideal conditions for achieving effective foamability and stability are still unknown. The majority of the experiments were conducted under ambient conditions. However, screening should be carried out under reservoir condition because it is important influence on foam enhanced oil recovery (EOR). As a result, in this work, foam qualities were examined at high temperatures and pressures as well as, in the presence of a synthetic formation brine. Firstly, preliminary experiments, which included surfactants and nanoparticles screening, were conducted. Three different ionic surfactant types were examined for this purpose at various temperatures, concentrations of monovalent and divalent salts, and a synthetic formation brine. Then, bulk foam stability investigations were carried out under ambient and thermobaric conditions. The morphology and texture of the foam were assessed using microscopic examinations. The ideal nano-augmented surfactant solution was then foamed with CO2 and used in core flooding studies.
- Europe (0.48)
- North America > United States (0.28)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (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)
- (2 more...)
Abstract Underground Hydrogen Storage (UHS) is an emerging technology to store energy, produced by renewable sources, into subsurface porous formations. UHS efficiency in depleted gas reservoirs can be affected by H2 biochemical degradation due to interactions with rock, brine and gas. In the reservoir, subsurface microorganisms can metabolize H2 with possible hydrogen losses, H2S production, clogging and formation damage. In this work we investigate the impact of hydrogen losses due to microbial activities on UHS operations in depleted gas reservoirs lying in sandstone formations. We developed a workflow to exploit the chemical reactive transport functionalities of a commercial reservoir simulator, to model biochemical processes occurring in UHS. Kinetic chemical reaction formulation was used to replicate a Monod's type microorganism growth, using PHREEQC to tune reaction parameters by matching a 0-D process in an ideal reactor. Then, we applied the methodology to evaluate the impact of biotic reactions on UHS operations in depleted gas fields. Eventually, various sensitivities were carried out considering injection/production cycles lengths, cushion gas volumes and microbial model parameters. Benchmark against PHREEQC demonstrated that, by properly tuning the kinetic reaction model coefficients, we are capable of adequately reproduce Monod-like growth and competition of different microbial community species. Field-scale results showed that hydrogen losses due to biochemistry are limited, even though this may depend on the availability of reactants in the specific environment: in this work we focus on gas reservoirs where the molar fraction of the key nutrient, CO2, is small (< 2%) and the formation is a typical sandstone. Operational parameters, e.g. storage cycle length, have an impact on the biochemical dynamics and, then, on the hydrogen degradation and generation of undesired by-products. Similar considerations hold for the model microbial growth kinetic parameters: in this study they were established using available literature data for calibration, but we envisage to tune them using experimental results on specific reservoirs. The current model set-up does not account for rock-fluid geochemical interactions, which may result in mineral precipitation/dissolution affecting the concentration of substrates available for biotic reactions. Nonetheless, it can provide an estimate of hydrogen consumption during storage in depleted gas reservoirs due to microbial activities. This study is among the first attempts to evaluate the impact of hydrogen losses by the presence of in situ microbial populations during hydrogen storage in a realistic depleted gas field. The assessment was performed by implementing a novel workflow to encapsulate biochemical reactions and bacterial dynamic-growth in commercial reservoir simulators, which may be applied to estimate the efficiency and associated risks of future UHS projects.
- Europe > Austria (0.28)
- North America > United States (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Overview (0.67)
- Research Report > New Finding (0.54)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.88)
- Geology > Geological Subdiscipline > Geochemistry (0.66)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > Natural gas storage (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...)
Polymer-Assisted-Water-Alternating-Gas for Improving the CO2 Flow Properties in Porous Media
Yegane, Mohsen Mirzaie (Department of Geosciences and Engineering, Delft University of Technology, Delft, The Netherlands / Dutch Polymer Institute (DPI), the Netherlands) | van Wieren, Thijs (Department of Geosciences and Engineering, Delft University of Technology, Delft, The Netherlands) | Fadili, Ali (Shell Global Solutions International B.V., The Hague, Netherlands) | van Batenburg, Diederik (Shell Global Solutions International B.V., The Hague, Netherlands) | Leblanc, Thierry (SNF S.A., ZAC de Milieux, France) | Zitha, Pacelli (Department of Geosciences and Engineering, Delft University of Technology, Delft, The Netherlands)
Abstract CO2 flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO2 mobility control and thus improved reservoir sweep efficiency, Water-Alternating-Gas (WAG) injection has often been applied. The effectiveness of WAG diminishes, however, due to the presence of micro-scale reservoir heterogeneity which results in an early breakthrough of gas. We propose Polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility, while also reducing the mobility of the aqueous phase, and consequently improving the performance of WAG. In this method, high molecular weight water-soluble polymers are added to the water slug. The goal of this work was to investigate the feasibility of PA-WAG and study the transport processes in porous media. An ATBS-based polymer (SAV 10 XV) was chosen as polymer and CO2 at immiscible conditions as gas. The objective of the experiments was to compare the performance of CO2, WAG, and PA-WAG injection schemes by conducting a series of X-ray computed tomography (CT)-aided core-flood experiments in Bentheimer cores. Core-flood results clearly demonstrated the beneficial effects of PA-WAG over WAG and continuous CO2 injection. Continuous injection of CO2 led to the recovery factor (RF) of only 39.0 ± 0.5% of the original oil in place (OOIP). In-situ visualization of CO2 displacement showed strong gravity segregation and viscous fingering because of the contrast in the viscosities and densities of CO2 and oil. The injection of WAG almost doubled the oil recovery (i.e., RF=76.0 ± 0.5%); however, the water and gas breakthroughs still occurred in the early stage of the injection (0.22 PV for water and 0.27 PV for CO2). The addition of the polymer to the aqueous phase delayed both the water and CO2 breakthrough (0.51 PV for water and 0.35 PV for CO2). This resulted in an additional 10% in the recovery factor. Using a single injection method, polymer adsorption was found to be 79.0 ± 0.5 μg polymer/g rock. The polymer adsorption can reduce the micro-scale permeability and as a result, mitigates the gas channeling. This in turn leads to the delay in CO2 breakthrough during PA-WAG injection as was evident from in-situ visualization. This experimental study demonstrated a positive response of PA-WAG compared to WAG and paves the way for its implementation in field applications.
- Europe > Netherlands (0.46)
- North America > United States (0.46)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Lista Formation (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- (2 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...)
An Intelligent Separated Zone Oil Production Technology Based on Electromagnetic Coupling Principle
Liao, Chenglong (Research Institute of Petroleum Exploration & Development, PetroChina) | Jia, Deli (Research Institute of Petroleum Exploration & Development, PetroChina) | Yang, Qinghai (Research Institute of Petroleum Exploration & Development, PetroChina) | Pei, Xiaohan (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhu, Yingjun (The Fourth Oil Production Plant of Daqing Oilfield Co., Ltd) | Kong, Lingwei (The Fourth Oil Production Plant of Daqing Oilfield Co., Ltd) | Yu, Yang (The Fourth Oil Production Plant of Daqing Oilfield Co., Ltd) | Du, Kai (The Fourth Oil Production Plant of Daqing Oilfield Co., Ltd)
Abstract Separated zone oil production technology is an important means to solve the interlayer and planar contradiction, fully develop the middle and low permeability layers, reduce the ineffective water circulation, and realize the remaining oil exploration in the high water cut stage of the oilfield. The existing technologies suffer from many problems, such as unsuitable for pump inspection operation, short working life, and poor communication reliability. This paper proposes an intelligent separated zone oil production technology based on electromagnetic coupling principle. The release-sub-involved pipe string structure is adopted, in which the production pipe string from the ground to the pump is connected by external binding cables, and multiple intelligent production allocators (IPAs) of the allocation pipe string are also connected by cables. The electromagnetic coupling principle is used to realize the close-range wireless transmission of power and data between the production and allocation strings. After the docking, the allocation pipe string can be powered from the ground, and two-way communication can be realized. This technology provides a repeatable downhole docking and detaching channel of power and data transmission, which eliminates the need to lift out the allocation pipe string during routine pump inspection operation, effectively increasing the working life of the IPA and reducing operation cost. The main components of this technology include ground communication controller (GCC), downhole electromagnetic coupling device (DECD), and IPA of each layer. The GCC is used to collect downhole monitoring data and adjust the zonal fluid production. The DECD consists of an inner cylinder tool and an outer cylinder tool. The inner cylinder tool is connected to a tubular pump, while outer cylinder tool is connected to the IPA. The average transmission efficiency and power of the DECD is 94% and 52 W respectively, and the error rate of data transmission is less than 1%. The IPA has the functions of temperature, pressure, flow rate monitoring and zonal fluid production adjusting, with a flow rate measurement range of 5∼100m/d, an accuracy of ±3% FS and a flow control valve of maximum overflow diameter of 15mm. The field trials of this technology were carried out in Daqing Oilfield and the experimental well was divided into two layers. The results showed that DECD was successfully docked. The measured downhole temperature was about 46°C, the maximum flow rate was 35 m/d, and the bottomhole flowing pressure was 9 MPa. This technology has the advantages of suitable for pump inspection operation, high communication reliability, and long working life, providing a new engineering technical means for alleviating the interlayer contradiction and improving reservoir recognition, which is expected to have a broad application prospect.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Louisiana > China Field (0.97)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.78)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (0.69)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.54)