Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Search injection pressure: Compositional effects during immiscible gas injection
...4 EVALUATING MISCIBLE AND IMMISCIBLE GAS INJECTION IN THE SAFAH FIELD, OMAN SPE29115 Safah there are no correlatable tight zones in the upper part of ...- EOS Model. Lean Gas Injection-Simulation of lean plant the formation that could act as barriers to ...gas segregation. A residue ...
...6 EVALUATING MISCIBLE AND IMMISCIBLE GAS INJECTION IN THE SAFAH FIELD, OMAN SPE 29115 and 2) lower ...gas injection rate, resulting in less total ...gas injected lean ...
...Society of Petroleum Engineers SPE 29115 Evaluating Miscible and Immiscible Gas Injection in the Safah Field, Oman Charles L. Hearn, Occidental International Exploration and Production Co...O. Box 833836, Richardson, TX 75083-3836, U.S.A. Telex, 163245 SPEUT. Abstract variables such as gas enrichment, well pattern configuration, and ...injection pressure on Safah oil recovery. The reservoir modeling approach presented in this paper illustrates...
Abstract The reservoir modeling approach presented in this paper illustrates how available engineering tools can be used to evaluate the technical feasibility and economics of high-pressure gas injection. The key components to such a study included:equation of state (EOS) modeling of experimental PVT data, matching miscible and immiscible slim tube results, and systematically reducing the number of components used in the EOS model to minimize computational requirements, studying numerical grid effects, displacement mechanisms, optimal well pattern, and injection pressure with 2D cross-section and 3D sector models, and comparing compositional results with simulations based on the black-oil PVT formulation used in full- field history matching and reservoir management modeling. Introduction Safah field, in northwest Oman, produces light oil from a low- permeability carbonate formation at 6500 ft. Produced gas is processed and the lean plant residue gas is reinjected at high pressure. Laboratory tests show that such injection can increase recovery by oil vaporization, swelling, and viscosity reduction, and that injecting a suitably enriched gas would develop miscibility. We used a PVT program, compositional model, and black-oil model to study these effects. The purposes of this paper are:to illustrate the evaluation process, showing how simulation can extend laboratory results and determine displacement mechanisms; and to show effects of operating variables such as gas enrichment, well pattern configuration, and injection pressure on Safah oil recovery. This paper focuses on the evaluation process, rather than on the performance of the present Safah gas injection project. Reservoir properties are summarized here; details of field geology, development, and operation are in previous papers. Safah produces 420 API, low viscosity (0.4 cp) oil from a recrystallized lime mud. Original oil-in-place was about 650 MMSTB. The reservoir rock has been altered by complex diagenesis, which contributes to a reservoir structure that is not strongly layered. Safah reservoir pay has generally high porosity, but permeability averages only about 5 md. The field has variable oil properties with both saturated and undersaturated oil areas. This paper concerns evaluation of gas injection in the under- saturated oil area. The BHP of injection wells in this area is over 4000 psi, compared to an initial reservoir pressure of 3100 psia and oil bubblepoint pressure about 2100 psia. Reservoir and oil properties are summarized in Table 1. Study Methods On the basis of standard and multicontact gas injection PVT data, Safah oil was characterized with an EOS-based PVT program using 15 components and the Peng-Robinson equation of state. Laboratory slim tube displacements using both lean and enriched gases were evaluated using a compositional simulator. This included the determination of minimum miscibility pressure (MMP) and displacement mechanisms for the lean and rich injection gases. P. 187
- Reservoir Description and Dynamics > Reservoir Simulation (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)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
... ratio is employed in simulating waterflooding outweigh the extra expense. project. The benefit of gas injection can be easily concluded from Figs. 4 and 5 provide the oil recovery comparison results the relation...e calculated recoveries at 1.2 proportional to the interfacial tension and inversely pore volume of gas or water ...injection are 41.98 and 49.95 % proportional to the pore throat radius. This indicates that as OOIP for mobil...
...e k r is higher permeabilities of 9 and 0.3 md, respectively. The ratio of compare with that of immiscible k r . Considerable amount of horizontal to vertical permeabilities of each layer is 10. In all ...recoverable oil is produces up to nearly seven years of gas of the simulation models the ...injection and production wells ...
...SPE 108014 Evaluating Reservoir Production Strategies in Miscible and Immiscible Gas-Injection Projects Iman Farzad, National Iranian Oil Co., and Mahmood Amani, Texas A&M U. at Qatar Copyrigh...t 2007, Society of Petroleum Engineers injection pressure, stratification and mobility ratio on the This paper was prepared for presentation at the... 2007 SPE Latin American and Caribbean performance recovery in miscible and immiscible flooding of Petroleum Engineering Conference held in Buenos Aires, Argentina, 15-18 April 2007. t...
Abstract Successful design and implementation of a miscible gas injection project depends upon the minimum miscibility pressure (MMP) and other factors such as reservoir and fluid characterization. The experimental methods available for determining MMP are both costly and time consuming. Therefore, the use of correlations that prove to be reliable for a wide range of fluid types would likely be considered acceptable for preliminary screening studies. This work includes a comparative evaluation of MMP correlations and thermodynamic models using an equation of state by PVTsim 1 software. We observed that none of the evaluated MMP correlations studied in this investigation is sufficiently reliable. EOS-based analytical methods seemed to be more conservative in predicting MMP values. Following an acceptable estimate of MMP, several compositional simulation runs were conducted to determine the sensitivity of the oil recovery to variations in injection pressure (at pressures above, equal to and below the estimated MMP), stratification and mobility ratio parameters in miscible and immiscible gas injection projects. Simulation results indicated that injection pressure was a key parameter that affects oil recovery to a high degree. MMP determined to be the optimum injection pressure. Stratification and mobility ratio could also affect the recovery efficiency of the reservoir in a variety of ways. Introduction Through the past decades, miscible displacement processes have been developed as a successful oil recovery method in many reservoirs. The successful design and implementation of a gas injection project depends on the favorable fluid and rock properties. The case studies using Eclipse 2 compositional simulator considered the effect of key parameters, such as injection pressure, stratification and mobility ratio on the performance recovery in miscible and immiscible flooding of the reservoir. However, accurate estimation of the minimum miscibility pressure is important in conducting numerous simulation runs. MMP is the minimum miscibility pressure which defines whether the displacement mechanism in the reservoir is miscible or immiscible. Thermodynamic models using an equation of state and appropriate MMP correlations were used in determining the MMP. Compositional simulation runs determined the sensitivity of the oil recovery to the variations in above mentioned parameters. Significant increase in oil recovery was observed when interfacial tension dependent relative permeability curves were used. These relative permeability curves provide an additional accounting for miscibility by using a weighted average between fully miscible and immiscible relative permeability curves. The local interfacial tension determines the interpolation factor which is used in obtaining a weighted average of immiscible and miscible (straight line) relative permeabilities. Simulation runs were performed at pressures below, equal to, and greater than estimated MMP for reservoir fluid/ injection gas system. Oil recovery was greatest when miscibility achieved. To investigate the effect of stratification on the performance recovery of the reservoir, the base relative permeability of two layers changed. Location of the high permeable layer (up or bottom layer) in the stratified reservoir greatly influenced the efficiency of the reservoir. Understanding the effect of interfacial tension and adverse mobility ratio on the efficiency of the gas injection project was the last case study. Injection gas and reservoir fluid compositions differed in such a way to have interfacial tension and mobility dominated mechanism. To investigate the effect of interfacial tension water was considered as a fluid with much higher surface tension values with the oil. Lower surface tension values between rich gas and reservoir fluid (interfacial tension dominated) made gas injection project a more competitive recovery method than waterflooding. In mobility dominated displacement mechanism (lean gas/reservoir fluid system) the viscous instabilities were more important than the interfacial tension effect. For this case, waterflooding with favorable mobility ratio resulted in higher oil recoveries.
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 186 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 115 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- 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)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Investigation of Effect of Gas Injection Pressure on Oil Recovery Accompanying CO2 Increasing in Injection Gas Composition
Abbasi, Saeed (Research Institute of Petroleum Industry (RIPI)) | Tavakkolian, Mohsen (Research Institute of Petroleum Industry (RIPI)) | Shahrabadi, Abbas (Research Institute of Petroleum Industry (RIPI))
...ver researchers revealed the importance of diffusion calculations burden pressure is applied. Water injection starts until and capillary pressure differences accompanying with surface stability condition and ...injection of 1PV. Afterward, oil tension due to ...compositional effects. is injected into sample and till 1PV and until no water Wylie et. al. investigated about mass tra...
...SPE 140749 Investigation of Effect of Gas Injection Pressure on Oil Recovery Accompanying CO2 Increasing in ...Injection Gas Composition Saeed Abbasi, Mohsen Tavakkolian, Abbas Shahrabadi, Research Institute of Petroleum In... Abstract should increase the reservoir energy, but also displace the oil toward production wells. Gas injection Gas injection is a common EOR method for increasing oil technique (especially miscible ...
...were analyzed due to alteration of Comparison of The Results: Comparison of three sets pressure and gas composition. Additionally, the results of of experiments (Fig. 14) showed that ...injection different runs were compared. pressure plays an important role in oil recovery mechanism, as it wa...s proved in first and second tests. Analysis of The Results: Higher pressure leads to entrance of injection gas into First Step (...
Abstract Gas injection is a common EOR method for increasing oil recovery factor. It is an economical method, especially in cases where the injection gas for such gas injection project is easily available. In this study, the performance of gas injection into one of the Iranian reservoirs is investigated. Three sets of core flood experiments were conducted. Each run was conducted at different composition and injection pressure. The results of experiments revealed the fact that the recovery efficiency depends strongly on the injection pressure. It should also be noted that gas enrichment using components leading miscibility could increase the recovery. The optimum enrichment level was also an affecting factor, which controls the overall efficiency of gas injection. In the last phase of this study, the minimum miscibility pressure of the injected gas and in-situ oil under operated conditions was calculated using simulation package. These simulation runs were conducted for different percentage of CO2 in injected gas. Results of these simulation runs were in a good agreement with experimental results. It was found that as the CO2 contents of the injected gas increased the minimum miscibility pressure (MMP) decreased. Displacing agent has a stronger effect in high pressures. It means that partial miscibility supplied by pressure buildup would lead to increasing recovery factor.
...IPTC 13266 Dynamic Asphaltene Behavior for Gas Injection Risk Analysis Hideharu Yonebayashi, INPEX; Ali Al Mutairi and Ali Al Habshi, ADMA-OPCO; and Daisuk... U.S.A., fax 1-972-952-9435. Abstract Asphaltene study is now becoming a regular menu as a part of gas injection studies 1-11 . The asphaltene onset pressure (AOP) is one of the most important factors to unde... . The simple experiments to measure AOP are usually conducted using mixture of reservoir fluid and injection gas, and various ...
...6 IPTC 13266 (2) In Well-4, after gas break-through, the compositions of accumulated ...gas were considered to become close compositions of the original ...injection gas. Therefore, APE might return to less VGD affected one which would make the bottomhole operating con...
...2 IPTC 13266 was originally a producer but had been parmanently disconnected during the GIP project. Moreover, the well has been part of the GIP surveillance program. Solid sample col...enerated by calibration with the measured AOP of the mixture: Well-3 reservoir fluid sample and the injection gas 50 mol% added. Through the modeling study, possible APEs were also developed for other mixtures (...injection gas 0 43.75 mol% added). Since the fluid samples of Well-3 were taken from a depth 90 ft shallower than...
Abstract Asphaltene study is now becoming a regular menu as a part of gas injection studies 1โ11. The asphaltene onset pressure (AOP) is one of the most important factors to understand asphaltene precipitating behavior. The SDS (solid detection system) based on light scattering technique has been quite popular and widely used in all over the world 1,7โ9,12โ15. The simple experiments to measure AOP are usually conducted using mixture of reservoir fluid and injection gas, and various gas mixing volume are assumed to be investigated. These various experimental specification of gas mixing volume are useful to understand asphaltene risks during gas injection projects. However, what this investigation can show is just a static asphaltene behavior, and sometimes might overlook true asphaltene risks. In the gas injection pilot (GIP) project in an offshore carbonate oil field in the Arabian Gulf, the static asphaltene behavior was studied by the SDS using NIR (neear infrared) light scattering technique. For this study, a single phase bottomhole sample was collected from the same producing zone, but the sampling location was 90 ft shallower than the GIP area. Various combination of mixtures (sampled reservoir fluid mixed with 0, 25, 37.5, 43.5 and 50 mol% injection gas) were examined to measure AOP. Furthermore, the numerical models were generated and calibrated with the experimental findings. In order to evaluate the asphaltene risks at the GIP area, the models were adjusted to the target oil composition by considering existing oil compositional gradient in the field. However, the modeling analyses showed that the operating conditions of producing wells are outside the estimated asphaltene precipitation envelope (APE). This result was inconsistent with the field fact, in which actual asphaltene deposits were observed and collected from bottomhole of some wells in the GIP area. Namely, we were obliged to judge that our current experimental results of static asphaltene behavior overlooked at the actual asphaltene risks. What is insufficient for a realistic modeling ? Our hypothesis is the dynamic asphaltene behavior. During gas injection process, the injected gas composition is changed due to vaporizing gas drive (VGD) mechanism, in which gas was enriched with the intermediate molecular weight hydrocarbons from reservoir oil. Our latest experimental investigation of static asphaltene behavior did not include this process. Therefore, the sensitivity analyses of the VGD effects were carried out with the calibrated model to realistically evaluate the actual APE. Various enriched gas composition were assumed, and the affects of these enriched gas on APE were investigated. Consequently, it was found that the enrichment of intermediate components expanded APE, and the operating condition of asphaltene problematic wells could be explained to be inside APE. Therefore, we concluded that the dynamic asphaltene behavior must be understood for a realistic risk evaluation in the gas injection project. Introduction Background and Histories The target field was discovered in 1963 and started production in 1967. It is currently operated by ADMA-OPCO. It produces from two carbonate reservoirs (A and B) and its oil is transported and processed at the plant near an island. To maintain reservoir pressure, the dump flood water injection started in 1972, followed by powered water injection in 1978 and the crestal gas injection in 2003. In addition to this project, gas injection pilot project at the flank area has been carried out at western flank area of the field.
- North America > United States > Texas (0.68)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.28)
- North America > United States > Montana > Roosevelt County (0.24)
- 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)
- (23 more...)
...2 SPE 132841 Immiscible/miscible hydrocarbon ...gas injection still is an important and effective recovery strategy for single porosity reservoirs but these EOR ... are methods of enhanced oil recovery proposed to mobilize the trapped oil. One of these methods is gas injection. Gravity drainage, physical diffusion, viscous and capillary forces, total pore compressibility, an...
...etation of simulated results difficult, and may lead to overprediction of MME if the numerical grid effects are not accounted for. On method to minimize spatial grid ...effects is to extrapolate the simulated recovery factors to an infinite number of grids. For example run sl...ferent enrichment levels using N 50,100 and 300 grid cells. The recovery factors at 1.2 PV injected gas (RF 1.2 ) are then plotted versus 1/ N separately for each enrichment level. To extrapolate to ...
...SPE 132841 Miscible Gas Injection Study in a Naturally Fractured Reservoir: A Case Study B. Moradi, SPE, Iranian Central Oil Fields ...may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Gas injection is the most widely applied process in enhanced oil recovery (EOR) for light oils. Most of the oil p...ion in the Middle East comes from carbonate reservoirs, the majority of which are highly fractured. Gas injection in fractured reservoirs has been used less than conventional single porosity reservoirs. Three natu...
Abstract Gas injection is the most widely applied process in enhanced oil recovery (EOR) for light oils. Most of the oil production in the Middle East comes from carbonate reservoirs, the majority of which are highly fractured. Gas injection in fractured reservoirs has been used less than conventional single porosity reservoirs. Three natural phenomena of gas channeling, viscous fingering and gravity over ride jeopardize the final oil recovery in gas injection projects. In fractured reservoir due to higher vertical permeability, and strictly higher rock heterogeneity, these phenomena are more probable and this fact will challenge the feasibility of gas injection projects in fractured reservoirs. In this work, miscible/immiscible gas injection was studied in a fractured reservoir through compositional simulation. The oil field under study is a fractured oil reservoir located in west of Iran. A homogenous DPSP (Dual Porosity-Single Permeability) synthetic model was generated which investigates the effect of molecular diffusion, displacement velocity, gas/oil fracture capillary pressure, slug size and injection pressure of injectant on final oil recovery of gas injection process. Minimum miscibility pressure (MMP) and Minimum miscibility enrichment (MME) of gas injection was determined using slim tube through compositional simulator. Three possible scenarios โ natural depletion, miscible gas injection and immiscible gas injection were compared. Results indicated that miscible injection yields better recoveries than the other, so miscible gas injection in this reservoir can be a potentially good scenario.
- North America (0.93)
- Asia > Middle East > Iran (0.34)
Feasibility Study of Gas Injection in Low Permeability Reservoirs of Changqing Oilfield
Tian, Ye (Colorado School of Mines) | Uzun, Ozan (Colorado School of Mines) | Shen, Yizi (Colorado School of Mines) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, PetroChina) | Yuan, Jiangru (Research Institute of Petroleum Exploration and Development, PetroChina) | Chen, Jiaheng (Research Institute of Petroleum Exploration and Development, PetroChina) | Kazemi, Hossein (Colorado School of Mines) | Wu, Yu-Shu (Colorado School of Mines)
...SPE-200469-MS 19 4. The simulation also showed increasing injection pressure would also help increase the recovery factor. Moreover, the leaner composition could be co...mpensated by higher injection pressure. The optimal ...injection duration and soaking time could also be obtained after sensitivity analysis. 5. ...
...SPE-200469-MS Feasibility Study of Gas Injection in Low Permeability Reservoirs of Changqing Oilfield Ye Tian, Ozan Uzun, and Yizi Shen, Colorado S... require additional IOR/EOR measures besides waterflood. Based on the promising results from recent gas injection pilots in North America, we investigated the feasibility of ...gas injection in the low permeability formation (Chang 6 3 ) of Changqing Oilfield. An eight-component fluid ...
...nductivities, relative permeability curves should be carefully tuned to match the water cut and BHP during the waterflood to improve the model's reliability. Figure. 3--Poor history-matching performance of... the black oil model is no longer valid when the transport process is strongly compositiondependent during gas injection, it should be replaced by a ...compositional model to improve the simulation accuracy (Tian et al., 2019). Hence, an equation-of-state (EOS) bas...
Abstract Changqing Oilfield is the largest petroleum-producing field in China and one-third of its oil production is attributed to the formations with permeability lower than 1 mD. The rapid oil rate decline and low recovery factor (RF) associated with those formations require additional IOR/EOR measures besides waterflood. Based on the promising results from recent gas injection pilots in North America, we investigated the feasibility of gas injection in the low permeability formation (Chang 63) of Changqing Oilfield. An eight-component fluid characterization, which fits both the constant composition expansion (CCE) test and separator test, was used in a numerical dual-porosity compositional model. A typical well pattern, composed of six vertical injectors and one horizontal producer, is selected for the modeling study. The input parameters, including relative permeability, fracture permeability, etc., were adjusted to achieve an acceptable history match of the production data. Huff-n-Puff using several gasesโlean gas (CH4), produced gas, rich gas (C2H6), and solvent (C3H8)โ were investigated and the results were compared with the current waterflood. The simulation results show that the richer the injected gas, the higher the oil production. C3H8 huff-n-puff achieved the best performance, increasing the cumulative oil production by a factor of 2.28 after 5 cycles, then followed by C2H6 as 1.34, produced gas as 1.08. CH4 alone demonstrated a lower recovery factor than waterflood, because its minimum miscibility pressure (MMP) is close to the maximum allowable injection pressure, i.e., the minimum horizontal stress. In addition, the horizontal producer was completed at the reservoir top and water injectors were placed at the bottom, which was originally designed to improve the waterflood by gravity segregation. Under such well placement design, the miscible oil bank, which forms at the injection front during vaporizing drive, will be displaced towards the reservoir bottom even out of the SRV, undermining the huff-n-puff performance. Injection with rich gas will be more compatible, as the miscible bank forms at the injection tail. Injecting produced gas enriched with C3H8 will hence achieve promising EOR performance. The simulation also shows that increasing injection pressure increases the recovery factor. The leaner composition of produced gas could be compensated by a higher injection pressure. The optimal injection duration and soaking time could also be obtained after sensitivity analysis. Another critical factor is the fracture network characterized by the dual-porosity model, as simulation with the single porosity model only shows minor improvement in RF even with C3H8. Our work confirmed the technical feasibility of injecting rich gas in the low permeability Chang 63 by compositional simulation. We also determined the key parameters for the operator to consider in the next phase of the project.
- Asia > China > Shaanxi Province (1.00)
- Asia > China > Gansu Province (1.00)
- Asia > China > Shanxi Province (0.92)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
- 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)
- (11 more...)
...SPE-175131-MS Simulation of Fracture-to-Fracture Gas Injection in an Oil-Rich Shale Peixi Zhu, Matthew T. Balhoff, and Kishore K. Mohanty, The University of Texa... copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Miscible gas injection is proposed here for improved oil recovery in unconventional, oil-rich shale reservoirs. The ultra-...low permeability of shale makes injection from well to well difficult; thus it is proposed that ...
...SPE-175131-MS 3 path that delivers the injected gas into the formation. Therefore, the consideration of hydraulic fractures has to be taken into accoun...t when modeling gas injection in shale. Sheng and Chen (2014) simulated ...gas injection in a fractured 0.1 D reservoir. While primary depletion resulted in nearly 6% original oil in place...
...rcentage of improvement in the field is equivalent to billions of barrels of oil. Traditional fluid injection such as water, efficient in most conventional reservoirs, is not viable in shale formations due to ...the low permeability of shale reservoirs. Injection of miscible ...gas, such as CO 2 or hydrocarbon ...
Abstract Miscible gas injection is proposed here for improved oil recovery in unconventional, oil-rich shale reservoirs. The ultra-low permeability of shale makes injection from well to well difficult; thus it is proposed that gas is injected into a hydraulic fracture along a horizontal well and production occurs from an adjacent fracture, intersecting the same well. Compositional reservoir modeling was performed to investigate the effectiveness of the proposed gas injection scheme. The computational domain consists of two hydrofrac half-stages along a horizontal well to capture detailed information of the fluid flow near the well bore. The results show 15.7% OOIP incremental recovery for the base model with matrix permeability kmatrix = 10 ฮผD over 5000 days (nearly 14 years) of CO2 injection, and 12.5% OOIP for the one with kmatrix = 1 ฮผD, indicating that the gas injection scheme has the potential to vastly improve oil recovery in oil-rich shale formations. The effects of reservoir properties and injection conditions on oil recovery were investigated by changing the injection pressure, reservoir heterogeneity, hydrofrac spacing, dispersion, and compositions of the injection gas. Increasing injection pressure leads to higher production before breakthrough and faster recovery of the oil in the stimulated region. Reducing the hydrofrac spacing has similar effect, although the production declines more rapidly after breakthrough. Introducing heterogeneity to the reservoir results in lower recovery, but the effect of spatial continuity (correlation length) on recovery is insignificant. It was also found that dispersion is mainly dominated by diffusion and mechanical dispersion is less important in most cases. Injection of hydrocarbon gas outperforms CO2, especially if the economics is also taken into account.
- North America > United States > North Dakota (1.00)
- North America > Canada (0.70)
- North America > United States > Montana (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.94)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Elm Coulee Field > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- (2 more...)
...2 SPE-213096-MS pressure above the Minimum Miscibility Pressure (MMP), the injection is miscible. In contrast, if the ...injection pressure is lower than the MMP, the ...injection is ...
...he higher recovery factors from the higher permeability sample compared to the lower sample at same injection pressure. However, while production increased with permeability, viscosity reduction decreased. Thi...rted by the noticeable reduction in the viscosity in the low permeability sample at low pressure -- immiscible. Furthermore, the lower perm system produced more oil beyond the breakthrough. May be due the nanop...on. References Jia, B., Tsau, J.-S., & Barati, R. (2019). A review of the current progress of CO2 injection EOR and carbon storage in shale oil reservoirs. Fuel, 236, 404-427. Enab, Khaled, and Hamid Emami-M...
...SPE-213096-MS 9 trends in the near miscible injection, both sample showed reduction in the oil viscosity. This reduction in viscosity is lower than the r...eduction in the higher pressure but reflects that miscibility was reached during this process. ...Immiscible injection The ...
Abstract The miscible gas injection has been a successful technique to overcome the low oil recovery by improving the oil mobility due to viscosity reduction. While many experimental studies defined the fundamentals of gas injection in heavy oil reservoirs, experimental studies of gas injection into condensate oil reservoirs are scarce. Therefore, this study provides a comprehensive investigation of the impact of the injection pressure and reservoir permeability on the efficiency of CO2 to improve oil recovery from oil condensate reservoirs. The efficiency of the injected gas at different injection pressure into different permeability rocks is evaluated as a function of the recovery factor and the viscosity reduction experimentally. Miscible gas injection experiments of different shale rock samples with different permeabilities saturated with condensate oil were conducted at 5 different injection pressures. The recovery factor will be used to investigate the effect of injection pressure in two distinctly saturated rock samples. These samples are saturated with condensate oil from the Eagle Ford formation. The Minimum Miscible Pressure is predicted from the compositions of the fluids, which is determined using gas chromatography. The gas is injected at different pressures, and the recovery factor is calculated at the gas breakthrough, the end of the injection (Injecting 3 PV), and at the abandonment pressure (100 psi). The viscosity of the collected oil at the end of each run is measured to determine the viscosity reduction value. The experimental results proved the success of CO2 injection in improving condensate oil production. A proportional relationship between the injection pressure and the recovery factor was observed. Moreover, a proportional relation was observed between the production and the permeability. However, the permeability and the viscosity reduction were observed to be inversely proportional. This observation was extended to the immiscible injection, where the oil viscosity was reduced by a small percentage. This reduction is translated to an existence of some level of miscibility within the pores of the lower permeability sample. This phenomenon could be caused due to the higher nanopore confinement pressure in the lower permeability samples.
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.82)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- 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)
- (5 more...)
...Preliminary Experimental Results of High-Pressure Nitrogen Injection for EOR Systems T. Ahmed, SPE. Montana Tech. U. D. Menzie, SPE, U. of Oklahoma H. Crichlow, ...al Services Summary Miscible-displacement processes have generally been solubility on oil recovery during gas injection. Vogel and recognized by the petroleum industry as an important Yarborough 10 conducted a numbe...unts of nitrogen. Since no previous studies have been undertaken to They reported that the solution-gas gravity, oil density, observe miscibility conditions directly ...
...TABLE 3-RESULTS OF OIL DISPLACEMENT BY NITROGEN AND WATER INJECTION Initial Initial Initial Oil Recovery at ...Injection Solution Oil Water Stock-Tank Bottom Temperature Displacing Pressure GOR Saturation Saturation Oil ...OF THE sake of brevity. GENERATED SLUG Run 1 Component Mol % The first run was performed at an injection pressure of N2 8.6 4,000 psi. ...
...TABLE 5-SUMMARY OF THE RESULTS OF RUNS 1 AND 2 Parameter Run 1 Run 2 Injection pressure, psi 4,000 5,000 Type of displacement miscible miscible Oil recovery at breakthrough, % 80... C 2 12.8 13.4 C 3 10.7 10.7 C 4 2.0 2.2 C 5 2.8 2.8 C 6 8.1 10.0 Distance from the injection point at which miscibility was achieved, It 82 between 48 and 72 Solution GOR, scf/STB 575 575 Oil ... API 43 43 TABLE 6-01L DISPLACEMENT RECOVERY-RUNS 5 AND 6 Initial Initial Initial Oil Recovery at Injection Oil Water Stock-Tank Oil Breakthrough Type of Displacing Pressure (saturation (saturation in Place ...
Summary Miscible-displacement processes have generally been recognized by the petroleum industry as an important enhanced oil recovery (EOR) method. Nitrogen flooding has become an attractive method for economical EOR. Since no previous studies have been undertaken to observe miscibility conditions directly during their development in an oil reservoir, a research program was initiated to investigate experimentally the mechanism by which miscibility could be achieved in a reservoir model undergoing high-pressure nitrogen injection. Several experiments were conducted in a low-permeability, consolidated sandpacked stainless-steel tube 125 ft long and 0.435 in. in diameter. The apparatus was designed to allow sampling at selected locations along the core tube enabling researchers to investigate fluid behavior during the process. A more-detailed representation of the nitrogen displacement process is formulated and the graphical chromatographic results are presented to illustrate the nitrogen miscibility in consolidated cores. Introduction Previous researchers have investigated, experimentally and theoretically, the problem of predicting the effects of dry-gas injection into a reservoir. Most earlier experimental studies were concerned primarily with the effects of changing pressure, temperature, and gas solubility on oil recovery during gas injection. Vogel and Yarborough conducted a number of laboratory tests on several different reservoir fluids to determine the effect of nitrogen contact by varying the amounts of nitrogen. They reported that the solution-gas gravity, oil density, and oil viscosity increased with continued contact by nitrogen. No previous studies have been conducted to observe miscibility conditions directly during their development in an oil reservoir. This experimental work was initiated to investigatecompositional changes taking place during displacing of crude oil by continuous high-pressure nitrogen injection, change in properties of the liquid and vapor phases during the nitrogen injection, miscible pressures for nitrogen displacement, and distance from the injection point at which miscibility would be achieved. Experimental Apparatus and Materials Apparatus The experiment was designed to studyvaporization of oil by high-pressure nitrogen injection, mechanisms of nitrogen multiple contact miscibility displacement, and compositional changes that take place between nitrogen and in-situ oil during the test. Fig. 1 shows a schematic of the equipment used to perform the experimental study. For the purpose of description, the laboratory apparatus may be divided into three parts: a laboratory oil reservoir model, an injection system, and a production and analytical system. SPEJ P. 339^
- Research Report > Experimental Study (0.88)
- Research Report > New Finding (0.68)
...). Depending on the modeling purpose, single-phase flow, multi-phase black-oil flow, or multi-phase compositional flow can be selected to model the flow in the reservoir, fracture, and wellbore domains. Aside from...2021), coupled proppant settling and fracture closure analysis (Zheng et al., 2020b), using natural gas foam as the fracturing fluid (Zheng and Sharma, 2020a), production history match in fractured well ...(Zheng and Sharma, 2020b) and huff-n-puff injection improved oil recovery (Williams et al., 2020; Zheng and Sharma, 2020c) and in conventional reservoi...
...MS Coupling a Geomechanical Reservoir and Fracturing Simulator with a Wellbore Model for Horizontal Injection Wells Shuang Zheng and Mukul Sharma, The University of Texas at Austin Copyright 2021, Society of...The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Reservoir cooling during waterflooding or waste-water ...injection can significantly alter the reservoir stress field by thermo-poro-elastic ...
...ure and improve oil production in conventional oil reservoirs. Typically, water is injected through injection wells to build up a pressure gradient towards production wells in a defined well pattern, aiming to... drive the oil towards the producers. Significant reservoir cooling happens during water ...injection because the large volume of injected water is much cooler than the reservoir pressure (Perkins and ...
Abstract Reservoir cooling during waterflooding or waste-water injection can significantly alter the reservoir stress field by thermo-poro-elastic effects. Colloidal particles in the injected water decrease the matrix permeability and buildup the injection pressure. Fractures may initiate and propagate from injectors. These fractures are of great concern for both environmental reasons and strong influence on reservoir sweep and oil recovery. This paper introduces methods to fully couple reservoir simulation with wellbore flow models in fractured injection wells. A method to fully couple reservoir-fracture-wellbore models was developed. Fluid flow, solid mechanics, energy balance, fracture propagation, and particle filtration are modelled in the reservoir, fracture and wellbore domains. Effective stress in the reservoir domain is altered by thermo-poro-elastic effects during cold water injection. Fracture initiation and propagation induced by thermal and filtration effects is modelled in the fracture domain. Particle filtration on the borehole and fracture surfaces is modelled by matrix permeability reduction and filter cake build-up. Leakoff through the borehole and fracture surface is balanced dynamically. The coupled nonlinear system of equations is solved implicitly using Newton-Raphson method. We validate our model with existing analytical solutions for simple cases. We show how the poro-elasticity effect, thermo-elasticity effect, water quality, and wellbore open/cased conditions influence well injectivity, induced fracture propagation and flow distribution. Simulation results show that water quality and thermal effects control fluid leak-off and fracture growth. While it is difficult to predict the exact location of fracture initiation due to reservoir heterogeneity, we proposed a reasonable method to handle fracture initiation without predefined fracture location in the water injection applications. In open-hole completions, this may lead to "thief" fractures propagating deep into the reservoir. Thermal stress changes in the injection zone are shown to be significant because of the combined effect of forced convection, heat conduction and poroelasticity. The accurate predictions of thermal stress in different reservoir layers allow us to study fracture height growth and containment numerically for the first time. We show that controlling the temperature and the injection water quality is also found to be an effective way to ensure fracture containment.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)