Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
New Mexico
A Study of the Impact of Permeability Barriers on Steam-Solvent Coinjection Using a Large-Scale Physical Model
Sheng, Kai (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Al-Gawfi, Abdullah (Saskatchewan Research Council) | Nakutnyy, Petro (Saskatchewan Research Council)
Abstract This paper presents a solvent-assisted steam-assisted gravity drainage (SA-SAGD) experiment using condensate in a large physical model. The main objective of this research was to study the impact of permeability barriers on the in-situ thermal/compositional flow and the produced bitumen properties in SA-SAGD using condensate. A pressure vessel of 0.425 m in diameter and 1.2 m in length contained unconsolidated sands and two horizontal shale plates as permeability barriers. The two shale plates were placed at different elevations above the injection well and horizontally staggered so that they could make the main hydraulic paths tortuous during the experiment. The sandpack had a porosity of 0.34 and a permeability of 5.6 D, and it was initially saturated with 95% Athabasca bitumen and 5% deionized water. After 24 hours of preheating, SA-SAGD with 2.8 mol% condensate was performed at 35 cm/min (cold-water equivalent) at 3500 kPa for 4 days. The production, injection, and temperature distribution were recorded. Produced oil samples were analyzed for density and asphaltene content. The sandpack was excavated after the experiment to analyze the oil saturation and asphaltene content in the remaining oil at different locations. Results were compared with the previous SAGD and SA-SAGD experiments using the same physical model with a homogeneous sandpack. Results showed that SA-SAGD was efficient in the presence of permeability barriers with a cumulative steam-to-oil ratio (SOR) that was two to three times smaller than that ofthe homogeneous SAGD case. Temperature data indicated that a steam chamber vertically expanded from the lower part to the upper part through tortuouspaths of lower temperatures.The emerging steam chamber above the shale plates occurred by convective heat from the injection well through lower-temperature hydraulic paths between shale plates. This should have involved light to intermediate solvent components that enabled the steam chamber to expand away from the injection well. This highlights the important role of volatile solvent components in the growth of a steam chamber in SA-SAGD under heterogeneity. The produced bitumen density in this research was closer to the original bitumen than in the homogeneous SA-SAGD case because the bitumen dilution and the solvent retention increased by the tortuous flow regime resulted in efficient drainage of oil at lower temperature.
- North America > Canada (0.46)
- North America > United States (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
Abstract The Hydraulic Fracturing Test Site (HFTS) in the Permian-Midland basin has bridged the gap between inferred and actual properties of in-situ hydraulic fractures by recovering almost 600 feet of the whole core through recently hydraulically fractured upper and middle Wolfcamp formations. In total, over 700 hydraulically induced fractures were encountered in the core and described, thus providing indisputable evidence of fractures and their attributes, including orientation, propagation direction, and composite proppant concentration. This fracture data, along with the collected diagnostics, support testing and calibration of the next generation fracture models for optimizing initial completion designs and well spacing. In addition, with a massive number of existing horizontal wells in the Permian, the collected data is also useful for designing and implementing enhanced oil recovery (EOR) pilots to improve resource recovery from the existing wells. It is known from the literature that the primary recovery from the shale wells is typically about 5-10% of the original oil in place. Therefore, tremendous potential exists in the Permian to recover additional hydrocarbons by implementing appropriate EOR techniques on the existing wells. To explore this concept, Laredo Petroleum and GTI have agreed to perform HFTS Phase-2 EOR field pilot near the original HFTS, supported by funding from the U.S. Department of Energy and industry sponsors. The Phase-2 EOR field pilot involves injecting field gas into a previously fracture stimulated well in order to produce additional oil using huff-and-puff technique. During the course of the EOR experiment, a second slant core well was drilled near the injection/production well to capture and describe some of the fractures which served as a conduit for the injected gas field during the injection or "huff" period and the produced fluids during the production or "puff" period. The overreaching goals of the HFTS Phase-2 EOR experiment is to determine the effectiveness of cycling gas injection in increasing the oil and gas recovery from the Wolfcamp shale. Specific objectives included: 1. Drill, core, and instrument a second slant core well to describe the fracture network in the vicinity of an EOR injector/producer well 2. Perform laboratory experiments to determine the phase behavior, including black oil study, slim tube analysis, swell testing, etc. 3. Demonstrate how natural gas and/or CO2 increases the oil recovery from Wolfcamp shale through core flooding experiments 4. Determine if pre-existing stimulated horizontal wells can be re-pressurized above the miscibility pressure using the field gas 5. Perform numerical 3D reservoir simulations to predict EOR injection/production performance 6. Instrument offset wells and collect diagnostic data during the cyclic gas injection and production test. This paper describes the EOR field pilot along with the collected data and performed analyses noted above.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.77)
- Geology > Geological Subdiscipline (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- 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)
- (6 more...)
- 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 > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Information Technology > Modeling & Simulation (0.66)
- Information Technology > Communications > Networks (0.46)
Use of In-Situ CO2 Generation in Liquid-Rich Shale
Ogbonnaya, Onyekachi (University of Oklahoma, Norman, Oklahoma, USA) | Wang, Shuoshi (Southwest Petroleum University, Chengdu, China) | Shiau, Benjamin (University of Oklahoma, Norman, Oklahoma, USA) | Harwell, Jeffrey (University of Oklahoma, Norman, Oklahoma, USA)
Abstract Modified in situ CO2 generation was explored as an improved tool to deliver CO2 indirectly to the target liquid rich shale formations. Once injected, the special CO2- generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO2. For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches. In this effort, in situ CO2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 °F. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism. Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort. Multiple researchers reported successful lab scale CO2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO2 generation potential for liquid rich shale reservoirs.
- North America > United States > Oklahoma (1.00)
- Europe (0.93)
- 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)
- (26 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (5 more...)
Abstract Decline curve analysis has been used as a reliable method to forecast conventional reservoir well production over the last decades. Recently, an increase in the demand for oil and gas has caused unconventional reservoirs to become a prominent source of energy. However, it is challenged if we still apply the decline curve analysis in unconventional reservoirs due to its limitations such as boundary dominated flow, constant operation condition, et al. Therefore, in this paper, two new methods are proposed using machine learning method to forecast well production in unconventional reservoirs, especially on the EOR pilot projects. The first method is the Neural Network, which allows the analysis of large quantities of data to discover meaningful patterns and relationships. Both peak production rate and hydraulic fracture parameters are used to be the key factors. Lastly, Neural Network technology is applied to investigate the relationship between key factors and oil production rate. The second method uses the Time Series Analysis. Time Series Analysis is one of the most applied data science techniques in business and finance. Since the properties of unconventional reservoir make the production prediction more difficult, it is safe to say that Time Series Analysis can yield good results on the production rate forecast. Field production data from over 1000 wells from different shale plays (Barnett, Bakken, Bone Springs, Eagle Ford oil, Eagle Ford gas, Fayetteville, Marcellus gas, Marcellus oil, Utica oil, and Woodford) is used to verify the feasibility of these two methods. The results indicate there is a good match between the available and predicated production data. The overall R values of Neural Network and Time Series Analysis are above 0.8, which demonstrates that Neural Network and Time Series Analysis are reliable to study the dataset and provide proper production prediction. Meanwhile, when dealing with the EOR production prediction, such as Huff-n-Puff, Time Series Analysis shows more accurate results than Neural Network. This paper proposes a thorough analysis of the feasibility of machine learning in multiple unconventional reservoirs. Instead of repeatedly fitting the production data by decline curve analysis, it also provides a more robust way and meaning reference for the evaluation of the wells.
Abstract Pilot tests of surfactant additives in completion fluid and gas huff n' puff in depleted wells have proven the possibility of production enhancement in unconventional liquid reservoirs (ULR). However, numerical simulation studies regarding EOR techniques neglect two important features of the ULR: extensive fracture discontinuity and high fracture density. This work explores how these two features effect depletion forecasts and EOR evaluation in ULR by applying discrete fracture network (DFN) modeling and optimized unstructured gridding. In this study, grid generation algorithms for Perpendicular Bisection (PEBI) gridding are improved to handle reservoirs with complex fracture geometry and high fracture intensity. The depletion behavior of the dual-porosity methods and the DFN method are compared based on the "sugar-cube" conceptual model. Data including outcrop maps and FMI log are used to characterize fracture network geometry and build DFN models to represent realistic stimulated tight reservoirs. Dynamic fluid flow models are calibrated through history matching of depletion. To properly model EOR processes at the field scale, results from publications of lab experiments regarding surfactant imbibition and CO2 huff n' puff are used to generate simulation parameters. A series of surfactant spontaneous imbibition and gas huff n' puff simulations are performed on those calibrated DFN models to study the impact of fracture geometry on EOR performance. Simulation results indicate that dual-porosity methods are not correct if the transient period of fracture-matrix flow lasts for extaned periods or the continuity of fractures is poor, both of which are very common in ULR. By tuning parameters within a reasonable range, DFN dynamic fluid flow models match the production data and can represent the realistic stimulated ULR. Surfactant assisted spontaneous imbibition (SASI) in the matrix domain results in a marginal production increase compared to water imbibition. It is found that wettability alteration incurred in the fracture system may play a more important role in production enhancement. Simulation results of gas huff n' puff indicate the main recovery mechanisms are re-pressurization and viscosity reduction characteristic of multicontact miscibility. And for reservoirs below the bubble-point, another recovery mechanism is the increase of heavy components' flux. However, either increasing the soak period or increasing the portion of the production period in each cycle has a minor effect on recovery enhancement. This study reveals the significance of using DFN with the unstructured grid to study the EOR processes in ULR. This approach can capture the rapid and extreme change in phase saturation and component fraction within the stimulated reservoir volume (SRV). Our results demonstrate the important factors that affect the field-scale EOR performance in ULR.
- North America > United States > Texas (1.00)
- North America > Canada (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geology > Petroleum Play Type > Unconventional Play (0.46)
Abstract The purpose of this paper is to (1) describe the mechanisms of gas-based enhanced oil recovery (EOR) in tight unconventionals, and (2) emphasize the need for single-porosity model tuning of the dual-porosity model when it is used to model EOR for unconventionals on well or field scale. We study two different gas-based EOR methods that inject and produce cyclically through the same well: The Huff-n-Puff (HnP) method, and a method we will refer to as the Fracture-to-Fracture (F2F) in which every other hydraulic fracture is used for injection and production in each cycle. We show that the recovery mechanisms and EOR target volume for HnP and F2F are fundamentally different. We argue that the target volume for HnP is a rubblized ("shattered") rock volume adjacent to the hydraulic fracture. To accurately predict the performance of this rubblized region, we use a compositional reservoir simulator that includes molecular diffusion to model the EOR performance of rubble-rock pieces of varying size. Gridding of numerical models is given considerable attention for both HnP and F2F to show its importance when modeling miscible EOR processes. Coarse gridding may result in significant numerical dispersion, which can falsely yield artificially optimistic recoveries for the HnP process. Results from this paper show that the primary recovery mechanism for HnP stems from a target EOR volume represented by a rubblized rock volume. The size of the rubble, and in particular its minimum dimension, will control the amount of gas that enters, mixes, and recovers oil from the rubble pore space through a process of Darcy flow, molecular diffusion, and phase behavior that involves swelling, vaporization, and first-contact miscibility conditions. The F2F method is not particularly affected by the rubblized region, but instead targets recovery from the entire rock volume between hydraulic fractures; this EOR process is akin to a conventional miscible-displacement mechanism with a much larger EOR target than HnP. The F2F method is presented in this paper as an alternative to the HnP method to show that HnP is not necessarily the best or the only EOR strategy in tight unconventionals. The EOR target volume for F2F is potentially much larger than for HnP, as everything between the fractures may be swept with a piston-like efficiency. However, the response time (i.e. the time before uplift in production is observed) can be much longer for F2F than HnP, depending mainly on the fracture spacing and matrix permeability.
- North America > United States > Texas (1.00)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (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)
- (3 more...)
Abstract The primary objective of this work was to investigate the results and the possible mechanisms of oil recovery in a huff-n-puff style improved oil recovery (IOR) field pilot using nanoparticle assisted CO2 injection. A secondary objective was to study the sensitivity of the process to injection volume of nanoparticles and gas, the type of injected gas, soaking period, and the timing of IOR to maximize net present value. An Eagle Ford shale well was produced for 526 days before 167-barrels of nanoparticle treatment and 160-tons of CO2 were injected in 11 cycles into the well, shut-in for 5 days and then put back on production. A simulation study was conducted using a fully coupled geomechanical compositional fracturing and reservoir simulator using data from the pilot well. The primary production was history matched for the fractured horizontal well and the huff-n-puff process with nanoparticle and CO2 injection was simulated followed by a shut-in period. The simulated production after shut-in and the incremental oil recovery was compared with field measured data. The pilot test results clearly show that there is a significant oil rate increase after the nanoparticle and CO2 are injected. Lab results show that nanoparticles can lower the interfacial tension between the water and oil and alter the rock wettability to a preferential water-wet state, which is beneficial for oil production. The simulation studies show that CO2 injection alone results in smaller improved oil recovery and predicts a smaller oil recovery than in the field. This suggests that both the nanoparticles and gas play an important role in increasing the relative permeability to oil and improving oil recovery. Results from the sensitivity study show that larger injection volumes of nanoparticles and gas result in higher oil recovery. Among different injection gases simulated, in this oily window of the Eagle Ford shale, ethane gives the highest oil recovery followed by CO2, methane, and nitrogen. A longer soaking period after the injection also helps to increase oil recovery. It is also shown that it may be better to perform IOR at an earlier stage of primary production to maximize the cumulative oil recovery. Our field and simulation results provide operators with significant new insights into the design of an IOR process that uses nanoparticles with CO2 injection. The integration of field pilot test data with realistic compositional geomechanical reservoir simulation for the first time provides a quantitative estimate of the improvement in oil recovery and insights into the possible mechanisms of oil recovery.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.55)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.81)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.81)
Abstract The sustained lower oil price for the last three years has shifted tight oil industry interest from an intensive drilling and completion based approach to more cost effective methods aimed at maximizing rates and ultimate recovery from existing wells. In that framework, application of conventional EOR methods to unconventional tight oil well has gained momentum in the recent period, with theoretical and experimental evaluation of approaches ranking from water and CO2 flooding to huff'n puff with chemicals. For that purpose, usual EOR experiments used for conventional rock cannot always be applied due to the extremely low volumes and permeability of tight reservoir rocks. This can lead to inaccurate results or extremely long experimental times. Here, we present a novel method for rapidly evaluating oil production by EOR methods in micro-Darcy permeability reservoir rock, and apply it to evaluate various chemical EOR approaches for unconventional tight oil wells. Our method relies on a fast screening and a continuous NMR monitoring of fluid saturations during imbibition experiments at reservoir temperature in miniaturized plugs. This permits to evaluate oil and water saturations in the rock samples as a function of time without having to interrupt the experiment for carrying out measurements. We validate this method by evaluating recovery from 10 μD sandstones and carbonates during imbibition of LowIFT formulations with various chemical additives. Despite the extremely low permeability, oil production from plugs using various chemicals can be evaluated and compared in less than 72 hours. Our new protocol shall be of interest to all laboratories trying to adapt EOR techniques to unconventional reservoirs, by permitting a real-time accurate and quantitative evaluation of various EOR options. In addition, the data we generated using various chemical EOR techniques support the interest of using low-IFT inspired chemical EOR methods to improve the ultimate recovery from tight reservoirs.
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
- Europe > France > Paris Basin (0.99)
Diffusion-Dominated Proxy Model for Solvent Injection in Ultra-Tight Oil Reservoirs
Cronin, M.. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Emami-Meybodi, H.. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Johns, R. T. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park)
Abstract Enhanced oil recovery (EOR) by solvent injection offers significant potential to increase recovery from shale oil reservoirs, which are typically between 3 and 7% OOIP. The rather sparse literature on this topic typically models these tight reservoirs based on conventional reservoir processes and mechanisms, such as by convective transport using Darcy's law, even though there is little physical justification for this treatment. The literature also downplays the importance of the soaking period in huff'n'puff In this paper we propose for the first time a more physically-realistic recovery mechanism based solely on diffusion-dominated transport. We develop a diffusion-dominated proxy model assuming first-contact miscibility (FCM) to provide rapid estimates of oil recovery for both primary production and the solvent huff'n'soak'n'puff (HSP) process in ultra-tight oil reservoirs. Simplified proxy models are developed to represent the major features of the fracture network. The key results show that diffusion-transport only can reproduce the primary production period within the Eagle Ford shale and model the HSP process well, without the need to use Darcy's law. The mechanism for recovery is based solely on density and concentration gradients. Primary production is a self-diffusion process, while the HSP process is based on counter-diffusion. Incremental recoveries by HSP are several times greater than primary production recoveries, showing significant promise in increasing oil recoveries. We calculate ultimate recoveries for both primary production and for the HSP process, and show that methane injection is preferred over carbon dioxide injection. We also show that the proxy model, to be accurate, must match the total matrix contact area and the ratio of effective to total contact area with time. These two parameters should be maximized for best recovery.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.92)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.86)
- 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)
- (8 more...)
- 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 > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- (3 more...)