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Collaborating Authors
Canadian Unconventional Resources and International Petroleum Conference
Abstract This paper is the report for the second stage research of nano-particle and surfactant-stabilized solvent-based emulsion experimental study for the heavy oil in Alaska North Slope Area. The core flooding studies under laboratory conditions were implemented after the bench tests, which is including the phase behavior test, rheology studies and interfacial tension measurement. And these studies provide the optimum selecting method for the nano-emulsion which could be used in the core flooding. The experiment results suggest this kind of emulsion flooding is a good optional EOR (enhanced oil recovery) process for heavy oil reservoirs in Alaska, Canada after primary production, where heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems. Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nanoemulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation. In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat. In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.90)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Experimental Characterization of Production Behavior Accompanying the Hydrate Reformation in Methane Hydrate Bearing Sediments
Ahn, T.. (Seoul National University) | Park, C.. (Kangwon National University) | Lee, J.. (Korea Institute of Geoscience and Mineral Resources) | Kang, J. M. (Seoul National University) | Nguyen, H. T. (Seoul National University)
Abstract The paper analyzed experimentally the production characteristics of hot-brine stimulation accompanying the hydrate reformation in the presence of methane hydrate. Many attempts have been to recover commercially the methane hydrate such as depressurization, thermal stimulation, and inhibitor injection. Hot-brine injection coupling thermal recovery with inhibitor injection has been investigated as one efficient production scheme but the hydrate reformation during the dissociation is problematic, that influences negatively the recovery rate. An experimental apparatus divided the steel body into 12 blocks not only to describe one-dimensional dissociation effectively but to control the temperature accurately. The specified amount of methane hydrate were formed artificially in unconsolidated and packed sediments where average particle size, absolute permeability, and porosity were 260 ฮผm, 4.4 D, and 42 %, respectively. The production trends were observed in the temperature range, 283.85 ~ 303.15 K and in the injection rate, 10 cc/min and 15 cc/min, respectively. Methane hydrate reformed in all tests, of which reason can be the recombination of water and dissociated methane at downstream zones. In early time, the production rate was low but it increased significantly in late time. The former was why most gas dissociated in upstream were consumed to reform hydrate in downstream while the latter was to combine both dissociation amount of initial and reformed hydrate. The dissociation front moved fast at the higher temperature and injection rate. The production efficiency of 15 cc/min and 294.55 K was similar to that of 10 cc/min and 303.15 K. The results confirmed the production behavior of methane hydrate under the reformation phenomenon and could provide with the fundamentals to develop the efficient production scheme based on hot-brine stimulation.
Abstract Restimulation treatments have been attempted in a wide variety of reservoirs, and more than 140 papers have been published documenting the success and failure of these efforts. A database of these published examples has been compiled and analyzed to identify the mechanisms responsible for production improvement following restimulation with propped fractures (refracs). A portion of this database was recently published (Vincent 2010), and specific field examples were highlighted to demonstrate that refrac treatments can improve production by numerous mechanisms including: โEnlarged fracture geometry โImproved pay coverage through increased fracture height in vertical wells โGreater lateral coverage in horizontal wells or initiation of more transverse fractures โIncreased fracture conductivity compared to initial frac โRestoration of fracture conductivity loss due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. โIncreased conductivity in previously unpropped or inadequately propped portions of fracture โUse of more suitable fracturing fluids โReorientation due to stress field alterations, leading to contact of "new" rock This paper will briefly review restimulation attempts in six Canadian reservoirs of interest to the local audience, and will then present a more detailed review of restimulation of horizontal wells in the unconventional Bakken oil formation. In addition to a summary of published results, this paper will introduce a significant amount of previously unpublished data regarding refrac treatments of horizontal laterals completed in the Middle Bakken. This study will identify several additional concerns and opportunities with restimulating horizontal wellbores that were not previously identified in literature reviews. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- North America > United States > Montana (1.00)
- (11 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Overview > Innovation (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.46)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Colombia > Putumayo Department > Putumayo Basin (0.99)
- Oceania > New Zealand > North Island > Taranaki Basin (0.99)
- North America > United States > Wyoming > Washakie Basin (0.99)
- (101 more...)
Abstract A unique workflow and methodology enabled analysis of production data using reservoir simulation to help understand the shale gas production mechanism and the effectiveness of stimulation treatments along the lateral of horizontal wells. Starting from early 2008, we have analyzed production data from more than 30 horizontal wells in the Haynesville Shale using this methodology. This paper presents case studies demonstrating results of this new technique in several different areas of the Haynesville Shale. After integration of all available data, we built simulation models for the wells stimulated with multistage hydraulic fracture treatments. This modeling work investigates factors and parameters relating to short- and long-term well performance including 1) pore pressure, 2) matrix rock quality, 3) natural fractures, 4) hydraulic fractures, and 5) complex fracture networks. By historymatching the observed production, we have identified the primary factors for creating good early well performance. The Haynesville study has provided a better understanding of the gas production mechanism and effectiveness of stimulation along the laterals. After calibration of the simulation model, effective well drainage area and reserve potential can be calculated with more confidence. The Haynesville Shale is a very tight source rock. The shale matrix quality correlates with production performance when stimulation treatments are consistent along the lateral. A complex fracture network created during the stimulation treatment is the key to generating superior early well performance in the Haynesville Shale. Knowing how to effectively create more surface area during treatment and preserve the surface area after treatment are critical factors for making better wells in the Haynesville. Operators can use this information to determine where and how to spend resources to produce better wells. It also helps refine expectations for well performance and minimizes the uncertainties of developing these properties. The workflow and methodology have also been successful in other shale plays.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- North America > United States > Arkansas (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.99)
- (2 more...)
Heavy Oil and Bitumen Recovery Using Radiofrequency Electromagnetic Irradiation and Electrical Heating: Theoretical Analysis and Field Scale Observations
Davletbaev, Alfred (RN-UfaNIPIneft - Rosneft) | Kovaleva, Liana (Bashkir State University) | Babadagli, Tayfun (University of Alberta) | Minnigalimov, Rais (Tatoilgas)
Abstract Heavy-oil and bitumen recovery from difficult geological media such as deep, heterogeneous and high shale content sands and carbonates, and oilshale reservoirs requires techniques other than conventional thermal and miscible injection methods. Materials in oil reservoirs (formation water, crude oil, oil-water emulsions, bitumen and their components like resins, asphaltenes, and paraffin) are non-magnetic dielectric materials with low electrical conductivity. If the electromagnetic field can be created to change these properties, electro-thermo controlled hydrodynamics could improve the displacement and recovery of heavy-oil/bitumen. This paper deals with the recovery improvement of heavy-oil/bitumen by Radio-Frequency (RF) Electromagnetic (EM) radiation. The RF-EM fields in the form of waves can penetrate deeply enough - from fractions of a meter to several hundred meters - into oil and gas containing reservoirs to generate heat and eventually improve recovery mainly due to the reduction of oil viscosity. The recovery mechanisms and the dynamics of the RF-EM heating process were analyzed for several field scale applications in Russia. In the Yultimirovskaya tar sand deposits, RF-EM energy was transmitted from the RF-EM generator, located at the surface, into the formation by a coaxial system of the well pipes. Another field example analyzed was the RF-EM stimulation process in several wells of the Mordovo-Karmalskaya tar sands performed in the 1980s. It was observed that the formation was heated to the temperature which was sufficient for injection of oxidant (air) to initiate fire flooding. Then, a mathematical model of this process was presented with a sample exercise. Some data needed for this exercise were obtained from the field tests evaluated. Field tests proved the efficiency of the RF-EM stimulation of heavy oil / bitumen deposits with low water cut values (in operating production wells with water cut <30% on early field development stages). Numerical simulations suggest that bottomhole temperature and heat/mass transfer effects in the reservoir can be controlled by setting the output performance of the RF generator and by the difference between the reservoir and bottom-hole pressure.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
- Africa > South Africa > Western Cape Province > Indian Ocean (0.24)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.97)
- North America > Canada (0.89)
Abstract In order to get a clear picture of the effectiveness of a multi-stage stimulation treatment pumped into the horizontal wellbore of a tight gas reservoir, one must integrate data from a number of different sources. This will provide a more complete forecast of the reservoir's development. The Montney formation straddles the British Columbia / Alberta border in the Western Canadian Sedimentary Basin. There is significant variability in the formation's properties across its area, but even so, we have seen a multitude of horizontal wellbores lined up within the formation in recent years. Many involved have questions about fracture spacing along a horizontal wellbore, and ultimately, the spacing of the horizontal wells in a field. The answers to these questions can lead to improved recovery factors and better economics for the resource play. In this case study, seven stages of Basal Doig / Upper Montney microseismic data are integrated with fracture pumping information, and finally incorporated into a reservoir simulator. Two years of production history from the Montney horizontal is matched to "calibrate" the four layer reservoir model and make it a predictive tool. This provides the basis for understanding of drainage radiuses around the fractures, and for recommendations on fracture spacing in order to optimize completions in subsequent wells. The calibrated reservoir model is then used as a predictive tool to understand drainage radius and productivity differences when the number of fracture stages in the wellbore is increased to reduce fracture spacing. Predictably, the cumulative production from the tight gas well with more stages is greater than the same well with fewer stages. Ultimately, there is an economic trade-off between completing the well with more stages and increased well productivity, and an optimal combination that differs from one region to the next.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (18 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Abstract The successful development and exploitation of unconventional reservoirs has relied on innovative technologies, such as horizontal drilling, multistage completions, modern multistage fracturing, and fracture mapping to pursue economic completions. It is important to highlight that economic production in these ultralow matrix-permeability reservoirs relies on conductivity that must be generated through hydraulic fractures and fracture-network systems. Simulations demonstrate that shale reservoirs with ultralow permeability require an interconnected fracture network of moderate conductivity (branch fractures) with relatively small spacing between fractures to obtain economic production rates and reasonable recovery factors. This paper discusses two recently developed hydraulic fracturing processes to improve economic recovery in unconventional reservoirs. The first new process is designed for multistage-fracturing treatments with high pumping rates and low proppant concentration. This method uses the efficiencies of tubing-deployed abrasive perforating. Proppant slurries are then pumped down the coiled tubing (CT) and nonabrasive clean fluid is pumped down the annulus, saving the permanent tubulars from erosion. As a result, the rate down the annulus can be much higher. The pumping rate can be instantly manipulated to customize the placement and concentration of proppant being pumped down the CT. In case of premature screenout, a well could be easily reverse-circulated and cleaned for the next stage. Wellbore proppant plugs eliminate the need for overflushing, and the new approach to fracture stimulation, known as branch fracturing, could be achieved by changing proppant concentration in real time. The second new process uses a combination of mechanically activated sleeve completions and fracturing of individual intervals with a change in the sequence in which the intervals are stimulated. This new method is proposed with the goal of altering the stress in the rock to facilitate branch fracturing and to connect to induced stress-relief fractures in a single, horizontal well.
- North America > United States > Texas (1.00)
- North America > Canada (0.68)
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock (0.35)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (2 more...)
Abstract Foamy oil viscosity is a controversial topic among researchers as to what happens to the apparent oil viscosity when the dispersed gas bubbles start migrating with the oil. For conventional oils, below the true bubble point pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent viscosity of gas-in-oil dispersion remains relatively constant, or perhaps declines slightly between the true bubble point and a characteristic lower pressure, called pseudo bubble point, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead oil value at atmospheric pressure. However, it is a well known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy oil viscosity being lower than the oil viscosity is counterintuitive. The major difference here is the extreme viscosity of the base liquid phase for foamy oil and how this interacts with the gas phase in a porous medium. The reported results appear to be very oil specific in this area, and are also a very strong function of how rapidly pressure is depleted in a given system. It is also likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity due to the size of dispersed bubbles being comparable to the pore sizes. This study aims to investigate this issue by measuring the foamy oil viscosity under varied conditions. The effect of several parameters, such as shear/flow rate, and gas volume fraction and type of viscometer employed, on foamy oil viscosity was experimentally evaluated. Three different viscosity measurement techniques, including Cambridge viscometer, capillary tube as well as a slim tube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling needle viscometer correlate better with the observed behavior in the slim tube than the capillary viscometer results. Also, unlike live oils, the apparent viscosity of foamy oils was flow rate dependent. Overall, the viscosity of foamy oil was found to be similar to live oil viscosity for a large range of gas volume fraction.
- North America > United States (0.94)
- North America > Canada > Alberta (0.48)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Mapping the microseismic activity during a hydraulic treatment is widely used to determine the geometry of the stimulated fracture network. Microseismic maps provide reliable information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Beyond that, these fracture geometries are used to better understand fracture modeling and even production characteristics. Fiber-optic-based distributed temperature sensing (DTS) arrays provide almost immediate updates of the near-wellbore temperature distribution in approximately one-meter intervals. In injection treatments, the near-wellbore temperature distribution can be used to determine isolation effectiveness, the relative amount of fluid each perforation cluster takes, fracture initiation points, and effective fluid diversion. In production analysis, DTS measurements can quantify production rates from each perforation interval, crossflow rates while shut-in, and fluid types recovered from each perforation interval. The detailed near-wellbore results available through DTS coupled with the far-field geometry acquired through microseismic mapping provide an accurate picture of the completion effectiveness. Microseismic mapping results often show adequate resolution over a large area but lack the fine resolution that would allow it to identify near-wellbore effects in the meter range. When modeling and interpreting the treatment geometry obtained by the microseismic-event distribution, it is important to include the correct near-wellbore effects, which are readily accessible through DTS measurements. Combining the two diagnostic tools is valuable for real-time decision making, post-treatment analysis, and production analysis to assess the completion effectiveness. Incorrect assumptions about perforation breakdown, fracture-initiation points, interval isolation, or limited-entry effectiveness can lead to misinterpretations of the microseismic results. Using both diagnostic tools provides firm answers to the overall completion effectiveness. This paper focuses on three distinct aspects of combining the analysis of microseismic mapping and DTS. The first is the real-time aspect, wherein real-time decisions and adjustments are made during the fracture treatment with the objective of manipulating the results towards the desired outcome. The second is using both tools to perform more accurate postfracture analysis, including calibrated fracture modeling, entry effectiveness, correct interval spacing, and stimulated reservoir volume (SRV) analysis. The third area covered is combining these diagnostic tools with a production analysis, which is acquired through analysis of the temperature data.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Overton Field (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Production Behaviour of Gas Hydrate Under Hot Sea Water Injection: Laboratory Case Study
Nengkoda, A.. (Schlumberger) | Budhijanto, B.. (Gadjah Mada University) | Supranto, S.. (Gadjah Mada University) | Prasetyo, I.. (Gadjah Mada University) | Purwono, S.. (Gadjah Mada University) | Sutijan, S.. (Gadjah Mada University)
Abstract In 2004, Indonesia has discovered 850 trillion cubic feet (tcf) of potential gas hydrate deposits as alternative energy to fuel oil at least in two locations, in South Sumatra's southern waters extending to West Java (625 tcf) and in the Sulawesi sea (233.2 tcf). The laboratory and simulation production behaviour of gas hydrate under hot sea water injection as alternative of Indonesia hydrate production, have been done under laboratory condition with combination of synthetic hydrate and porous sediment. Some flow assurance challange issued also have been investigated. These preliminary study are to investigate the temperature profile distribution, operational parameters and flowing characteristics of the dissociated gas and water from hydrate in porous sediment systems under synthetic hydrate and experimental setup. The experiments have been conducted by injecting hot sea water where composition is near to Indonesian sea water characteristics with different temperatures and rates. The result find that the gas production rate increases with time until reach maximum, and then it begins to decrease. The injection water temperature and rate, as well as the hydrate content in the synthetic sediment, all influence the energy ratio of thermal stimulation production. The high temperature sea water injection found potentially creating scale problems.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.94)