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Results
Abstract Foaming injected gas has the potential to overcome operational challenges encountered with pure gas injection. A mechanistic population balance model that integrates observed pore level events that are responsible for foam generation and coalescence in porous media was developed. The model is integrated in the AD-GPRS framework (Automatic Differentiation-General Purpose Research Simulator). Based on experimental pore-scale observations that show that the Roof snap-off geometric requirement for foam generation is affected due to the presence of residual oil in the pore, we upscale the pore-scale observations to the macroscale. We use experimental coreflood data from the literature to verify the performance of the model developed. The coreflood data are of two experiments that use the same core to perform a foam flood with and without the presence of oil. Pore-scale observations that show the effect of residual oil on the geometric Roof snap-off requirement translate into less germination sites at the macroscale. The generation constant used in the population balance model in the absence of residual oil reduces to one-fourth its original value when oil is present. The model developed was able to describe experimental data with good agreement both in the presence and absence of oil. In the presence of residual oil, all other foam parameters needed for the population balance model were fixed except the generation constant. The results demonstrate that the "hindered snap-off concept is able to describe foam flow when only residual oil is present.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- (2 more...)
Enhanced Oil Recovery Experiments in Wolfcamp Outcrop Cores and Synthetic Cores to Assess Contribution of Pore-Scale Processes
Kamruzzaman, Asm (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Kneafsey, Timothy J (Lawrence Berkeley Laboratory) | Reagan, Matthew T (Lawrence Berkeley Laboratory)
Abstract This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recovery—both for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution. We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160°F using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a ‘huff-and-puff’ process. The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm while it was 6.98 cm in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs. The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture. This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EOR—both in presence and absence of interconnected micro- and macro-fractures in the flow path. Finally, the CO2 injection results quantify the CCUS efficacy in regard to the amount of sequestered CO2 from pore trapping in the early reservoir life. For the long-term CO2 trapping, one needs to include the chemical interaction of CO2 with the formation brine and rock matrix.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.89)
- Overview (0.67)
- Research Report (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- 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)
Abstract Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs begs for utilization of tertiary recovery techniques. Enhanced Oil Recovery (EOR) via cyclic gas injection ("huff ‘n puff") has indeed enhanced oil recovery in many fields and many of those projects have also been documented in industry technical papers/case studies. But the need remains to document new techniques in new reservoirs. This paper documents a small scale EOR pilot project in the eastern Eagle Ford and shows promising well results. In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes and the learnings from each cycle led to adjustments and facility changes to improve the next cycle. After completing five injection/withdrawal cycles in the pilot a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable allowing for economic modeling to be utilized to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Development of Bio-Based Surfactant Foams for Hydrocarbon Gas Disposal Applications
Jin, Julia (Chevron Technical Center, a Division of Chevron USA Inc.) | Zuo, Lin (Chevron Technical Center, a Division of Chevron USA Inc.) | Pinnawala, Gayani (Chevron Technical Center, a Division of Chevron USA Inc.) | Linnemeyer, Harold (Chevron Technical Center, a Division of Chevron USA Inc.) | Griffith, Christopher (Chevron Technical Center, a Division of Chevron USA Inc.) | Zhou, Jimin (Chevron Technical Center, a Division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a Division of Chevron USA Inc.)
Abstract There has been increasing interest in different greenhouse gas (GHG) management strategies including the reduction of methane emissions and carbon sequestration. It has been proposed that reinjection of excess produced natural gas can mitigate GHG emissions without compromising oil production. Foam has been used as a method to reduce gas mobility, delay gas breakthrough, and improve sweep efficiency. However, industrial production of petroleum-based chemicals or surfactants to generate foam can be dependent on fossil-based resources that can be scarce or expensive. The main objective of this work was to reduce chemical cost and oil-based chemical dependency by developing an alternative biosurfactant formulation to generate high quality foam. Biosurfactant blends were ranked in comparison to single component anionic and nonionic surfactants and other commercially available surfactant blends. Bulk stability "shake tests" were done to look at initial foamability and stability of the different candidates and then corefloods in sandpacks and surrogate rocks were completed to look at if formulations would generate foam in porous media with methane gas and in the presence of crude oil. Experiments showed success in replicating chemical performance by replacing traditional oil-based surfactants with bio-based lignin derived surfactants even at reservoir conditions. High-quality biosurfactant foams reduced chemical costs, provided an alternative method to dispose of large amounts of hydrocarbon gas, and improved oil recovery through foam displacement.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
Abstract As the unconventional shale development matures, the industry has been actively seeking new ways to unlock incremental value beyond primary depletion. In particular, the miscible gas injection EOR via huff-and-puff technique has garnered interest in recent years. However, the pilot tests in the field have shown lower recoveries than initially predicted by laboratory and simulation studies. The objective of this study was to develop a systematic approach to upscale the EOR results from laboratory scale to field scale and better predict recoveries. One of the issues with existing laboratory and modeling studies is the assumption of constant-pressure or constant-rate boundary conditions at the fracture interface during the soaking stage, which is rarely achieved. A mathematical model is developed to represent this scenario better by modeling mass diffusion of a limited volume of well-stirred fluid in a non-porous body (remaining injected gas in the fracture network at the end of injection phase as compressed gas) into a porous medium (matrix). The matrix is characterized as an ensemble of rock pillars separated by fracture discontinuities to represent field conditions better. The rock pillars are of different thicknesses, with their thickness gradually increasing, moving away from the main fracture cluster. And finally, the concept of Dynamic Penetration Volume, which controls the amount of contacted oil by the EOR agent, is explored further as a function of the micro-fracture distribution function. Ultimately, this information was used to derive an updated a priori equation to better predict recovery factors of EOR processes in the field. For upscaling, we integrated concepts from both geomechanics and fluid flow. We used an existing correlation relating the fracture frequency & distribution observed in the lab-scale experiments to the fracture density in the field. By doing so, we can upscale the micro-fracture distribution to their field-scale counterparts. Although diffusion is the main transport & recovery mechanism, this study found that the fracture geometry created near-wellbore, i.e., fracture spacing & distribution, has a first-order effect on the efficacy of the huff-and-puff process in the field. It was also observed that by varying the soaking times of each cycle, the issue of penetration length could be resolved (as it increases as a function of √time). Additionally, focusing on understanding the near-wellbore fracture geometry would help operators optimize their gas injection schemes. The updated upscaling equation will help understand the huff-and-puff process better and predict the expected recoveries in the field more accurately. Additionally, it would help operators adjust and optimize soaking times for the process using a mechanistic approach.
- North America > United States > Texas (1.00)
- North America > Canada (0.93)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- 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 > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (4 more...)
Development of Site Characterization and Numerical Modeling Workflow of Acid Gas Injection for MRV-45Q Application
Acheampong, Samuel (New Mexico Institute of Mining and Technology) | Ampomah, William (New Mexico Institute of Mining and Technology) | Tu, Jiawei (New Mexico Institute of Mining and Technology) | Balch, Robert (New Mexico Institute of Mining and Technology) | Eales, Matt (Lucid Energy Group) | Trentham, Robert (The University of Texas Permian Basin) | Esser, Richard (University of Utah) | Cady, Candace (CandaceCCady Consulting, LLC) | Cather, Martha (New Mexico Institute of Mining and Technology) | George, El-Kaseeh (New Mexico Institute of Mining and Technology)
Abstract As part of the project funded under the Carbon Utilization and Storage Partnership (CUSP) of the Western United States, this paper demonstrates a workflow including site characterization and numerical simulation efforts of proposing a Monitoring, Reporting, and Verification (MRV) plan to the U.S. Environmental Protection Agency (EPA) for approval according to 40 CFR 98.440 (c)(1), Subpart RR of the Greenhouse Gas Reporting Program (GHGRP) to qualify for the tax credit in section 45Q of the federal Internal Revenue Services (IRS) Code. In this project, the injectors and treated acid gas (TAG) plant are located at the northern margin of the Delaware Basin, a highly productive hydrocarbon basin in southeastern New Mexico. The target injection zones are the Permian-aged Cherry Canyon Formation for the acid gas injection (AGI) #1 well and Siluro-Devonian formations for the AGI #2 well, storage zones above and beneath active hydrocarbon pay zones respectively. The storage zones and caprocks are characterized through well log examinations, formation fluid chemistry evaluation, faults identification and interpretation. Reservoir models were constructed and simulation performed to predict the extent of the TAG plume after 30 years of injection with 5 years of post-injection site care monitoring. The reservoir mapping and cross sections interpreted from well logs indicate that the area around AGI #1 does not contain visible faulting or offsets that might influence fluid migration, suggesting that injected fluid would spread radially from the point of injection with a small elliptical component to the south. In the Siluro-Devonian formation, where AGI #2 is planned to be completed. The induced-seismicity risk assessment shows that the operation of the proposed injection combined with the historic volume contributions of the regional saltwater disposal (SWD) wells is not anticipated to contribute significantly to injection-induced fault slip. This result demonstrates that acid gas can be injected as proposed while maintaining the minimal risk of induced seismicity. The water sample collected from a nearby well indicates that the formation waters are highly saline (180,000 ppm NaCl) and compatible with the proposed injection. The reservoir simulation results indicate that the TAG plume is predicted to extend a maximum of 1.2 km from the injector wellbore when the identified faults are treated as non-transmissive and 0.90 km when they are treated as transmissive. The pressure profiles demonstrate the strong potential for safe injection into both target formations. In December 2021, the United States Environmental Protection Agency (EPA) approved the Monitoring, Reporting, and Verification (MRV) plan, permitting Lucid Energy to sequester acid gas from its Red Hills gas processing complex in Lea County, New Mexico. This paper provides the industry with a critical roadmap for converting existing injectors into CO2 or TAG sequestration wells that may qualify for 45Q tax certification to comply with the current administrative regulations. As part of the project funded by Carbon Utilization and Storage Partnership (CUSP) of the Western United States, published data from this project is invaluable.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico > Lea County (0.24)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Phanerozoic > Paleozoic > Permian (0.89)
- Phanerozoic > Paleozoic > Devonian (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Structural Geology (0.88)
- Geology > Petroleum Play Type (0.66)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
- (31 more...)
New Paradigm in the Understanding of In Situ Combustion: The Nature of the Fuel and the Important Role of Vapor Phase Combustion
Gutiérrez, Dubert (AnBound Energy Inc.) | Mallory, Don (University of Calgary) | Moore, Gord (University of Calgary) | Mehta, Raj (University of Calgary) | Ursenbach, Matt (University of Calgary) | Bernal, Andrea (AnBound Energy Inc.)
Abstract Historically, the air injection literature has stated that the main fuel for the in situ combustion (ISC) process is the carbon-rich, solid-like residue resulting from distillation, oxidation, and thermal cracking of the residual oil near the combustion front, commonly referred to as "coke". At first glance, that assumption may appear sound, since many combustion tube tests reveal a "coke bank" at the point of termination of the combustion front. However, when one examines both the laboratory results from tests conducted on various oils at reservoir conditions, and historical field data from different sources, the conclusion may be different than what has been assumed. For instance, combustion tube tests performed on light oils rarely display any significant sign of coke deposition, which would make them poor candidates for air injection; nevertheless, they have been some of the most successful ISC projects. It is proposed that the main fuel consumed by the ISC process may not be the solid-like residue, but light hydrocarbon fractions that experience combustion reactions in the gas phase. This vapor fuel forms as a result of oxidative and thermal cracking of the original and oxidized oil fractions. An analysis of different oxidation experiments performed on oil samples ranging from 6.5 to 38.8°API, at reservoir pressures, indicates that this behavior is consistent across this wide density spectrum, even in the absence of coke. While coke will form as a result of the low temperature oxidation of heavy oil fractions, and while thermal cracking of those fractions on the pathway to coke may produce vapor components which may themselves burn, the coke itself is not likely the main fuel for the process, particularly for lighter oils. This paper presents a new theory regarding the nature and formation of the main fuel utilized by the ISC process. It discusses the fundamental concepts associated with the proposed theory, and it summarizes the experimental laboratory evidence and the field evidence which support the concept. This new theory does still share much common ground with the current understanding of the ISC process, but with a twist. The new insights result from the analysis of laboratory tests performed on lighter oils at reservoir pressures; data which was not available at the time that the original ISC concepts were developed. This material suggests a complete change to one of the most important paradigms related to the ISC process, which is the nature and source of the fuel. This affects the way we understand the process, but provides a unified and consistent theory, which is important for the modelling efforts and overall development of a technology that has the potential to unlock many reserves from conventional and unconventional reservoirs.
- North America > United States (1.00)
- Europe (1.00)
- North America > Canada > Alberta (0.94)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.90)
- Geology > Geological Subdiscipline (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
- North America > United States > Nebraska > Sloss Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > United States > South Dakota > Williston Basin > Buffalo Field > Red River Formation (0.94)
- North America > United States > North Dakota > Medicine Pole Hills Field (0.94)
Abstract The primary objectives of this study are to design a gas injection pilot in the Eagle Ford and to estimate the benefits of gas injection under different operational scenarios. This pilot design study entails the construction of multiple reservoir simulation models to understand the hydraulic fracturing and flow dynamics of multiple wells and gas injection operations in the Eagle Ford. Two DSUs with multiple hydraulically fractured wells were studied to achieve the proposed objectives. One of the DSUs was identified as the main study area to design a huff-and-puff gas injection pilot. Having an existing gas injection operation, the other DSU was selected to improve our understanding of the physics associated with gas injection. A dual porosity numerical reservoir simulation model coupled with geo-mechanics was built to replicate the historical well performances of the pilot area using a sophisticated numerical reservoir simulator. Another dual porosity simulation model was constructed to assimilate the existing huff-and-puff performance of the second DSU in which data was only publically available. The methodology used in this study integrates the hydraulic fracturing process, multi-phase flow, geo-mechanics, and proppant transport within the reservoir simulation. The simulation model was calibrated to match the historical hydraulic fracture treatment, fluid flow back and post-stimulation production. The proppant entrapment and migration from child well to the parent well was captured. The calibrated simulation model was then utilized to design a huff-and-puff gas injection pilot. Learnings and observations obtained from modeling of the existing gas injection operation in the second DSU were integrated into the pilot model. Additional sensitivity runs were performed to examine the potential benefits of gas injection under different operational scenarios. The calibration results indicated that the stimulated rock volume geometries of pilot study wells vary based on their completion practices. The historically observed well interference and frac hits between parent and child wells were captured by establishing a proper connectivity between wells during calibration. Proppant entrapment and movement of the proppant impacted the well performance. The results showed that significant amount of depletion leads to considerable matrix permeability reduction around wells. The most important knowledge gained from the calibration of the second DSU with huff-and-puff data is the identification of reservoir model characteristics that have the largest impact on the huff-and-puff performance. This study allows us to identify opportunities to design and improve huff-and-puff operation as well as estimating benefits of gas injection under different operational scenarios. The utilized technology in this study is unique and novel as it solves the geomechanics and flow in a single process. Proppant flow and entrapment was captured successfully. The multi-well calibration of the simulation model provides physics-based explanations for the historical well performances in the Eagle Ford.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.98)
- (12 more...)
A Novel Gas Dispersible Foam Technology Can Improve the Efficiency of Gas Injection Processes for IOR-EOR Operations in Unconventional Reservoirs
Díez, Kelly (Gastim Technologies) | Ocampo, Alonso (Gastim Technologies) | Restrepo, Alejandro (Gastim Technologies) | Patiño, Jonny (Gastim Technologies) | Rayo, Juan (Gastim Technologies) | Ayala, Diego (Gastim Technologies) | Rueda, Luis (Gastim Technologies)
Abstract Gas injection has become one of the most investigated methods for enhanced oil recovery in unconventional reservoirs. Nonetheless, the presence of natural and induced fractures negatively impacts the gas injection efficiency due to its channeling towards nearby wells or poor coverage in the treated area due to lack of conformance. To overcome these difficulties and boost the oil recovery process by gas injection, this work presents a novel gas dispersible foam technology to improve the sweep efficiency of gas injection in unconventional IOR/EOR projects. The development and evaluation of this technology has passed through a series of laboratory assurance stages that include fluids characterization, compatibility, and extensive coreflooding tests. A modelling approach is also presented, which was validated using lab and field data taken from the implementation of the technique in an extremely low porosity, tight and naturally fractured quartz-arenite gas condensate reservoir in Colombia. The workflow herein presented encompasses interdisciplinary components such as laboratory evaluation, reservoir modeling, treatment design, and wellsite setup and execution. Laboratory testing and inter-well field applications results, along with the development and testing of a phenomenological modelling approach, demonstrate that the gas dispersible foam injection can be a high potential technique for oil and/or condensate recovery in unconventional reservoirs given its proven ability to improve the deep reservoir gas conformance and avoid the lack of gas containment during gas injection IOR/EOR in unconventional plays. Lab results in a tight naturally fractured sample, suggest that the estimated incremental oil recovery was ~36% and the effective gas mobility reduction was ~45%. This technique also exhibited less chemical adsorption losses, which contributes to better chemical emplacement and longer durability. The main results of the field application, including a progressive decrease in gas injectivity at the gas injector, a consistent reduction in GOR with an associated oil increase at the influenced producer well, and a reported treatment durability of ~ 6 months, were all properly represented by the model. Each step of the workflow herein proposed not only assures the gas-based projects success, but also allows for smaller logistics footprint at the well location, along with less water consumption, which translates into cheaper and more efficient gas injection conformance operations.
Abstract Gas injection huff and puff (HnP) has been successfully applied in parts of Eagle Ford over the past few years. The success is attributed to gas and oil miscibility achieved by injection of gas at high pressure and rate in a contained hydraulic fracture system with a considerable of stimulated volume. Two key preliminary steps in gas HnP modeling include characterization of reservoir fluid (and its interaction with injected gas) and evaluation of hydraulic fracture system. This study focuses on simplified analytical tools for estimation of stimulated reservoir size from production data. Rate-transient analysis (RTA) is a tool for identification of flow regimes and estimation of key performance metrics for multi-fractured horizontal wells. The flow regimes include enhanced fractured region (EFR), bilinear flow, transient linear flow, transitional flow, and boundary-dominated flow. In this study, the size of stimulated rock and total effective fracture area are estimated using an RTA method. Further, diagnostics fracture injection tests (DFITs) and pressure buildup tests are used to characterize the multi-fractured horizontal wells for the purpose of gas EOR evaluation. Inter-well communication test is used to quantify the conductivity of connecting fractures between communication wells. This study helps the engineers and managers with reservoir and hydraulic fracture characterization and the screening process for gas HnP candidates. The outputs of these methods serve as first pass of SRV size for more detailed numerical modeling studies.
- North America > United States (0.68)
- North America > Canada > Alberta (0.47)