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Saint, A. "Drop or drill? [oil&gas policy]." Engineering & Technology 16, no. 1 (February 1, 2021): 40–41. http://dx.doi.org/10.1049/et.2021.0106.
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Smith, N. "North sea oil: a tale of two countries [Oil & Gas Industry]." Engineering & Technology 16, no. 1 (February 1, 2021): 30–33. http://dx.doi.org/10.1049/et.2021.0104.
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Maslin, E. "Oil & Gas - Decommissioning. Salvage ,Sink or Save? [North Sea oil decommissioning]." Engineering & Technology 15, no. 1 (February 1, 2020): 60–63. http://dx.doi.org/10.1049/et.2020.0109.
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Maslin, E. "Emission impossible? decarbonising hydrocarbons [oil&gas environment]." Engineering & Technology 16, no. 1 (February 1, 2021): 36–39. http://dx.doi.org/10.1049/et.2021.0110.
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Hitchin, P. "UK oil and gas: Squeezing the last drop." Engineering & Technology 9, no. 9 (October 1, 2014): 77–9. http://dx.doi.org/10.1049/et.2014.0925.
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Kosisko, K. "Oil and Gas - Automation. Factory on the sea floor." Engineering & Technology 15, no. 2 (March 1, 2020): 48–49. http://dx.doi.org/10.1049/et.2020.0206.
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Tang, Guo-Qing, Akshay Sahni, Frederic Gadelle, Mridul Kumar, and Anthony R. Kovscek. "Heavy-Oil Solution Gas Drive in Consolidated and Unconsolidated Rock." SPE Journal 11, no. 02 (June 1, 2006): 259–68. http://dx.doi.org/10.2118/87226-pa.
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Summary Solution gas drive is effective to recover heavy oil from some reservoirs. Characterization of the relevant recovery mechanisms, however, remains an open question. In this work, we present an experimental study of the solution gas drive behavior of a 9°API crude oil with an initial solution gas/oil ratio (GOR) of 105 scf/STB and live-oil viscosity of 258 cp at 178°F. Constant rate depletions are conducted in a composite core (consolidated) and a sandpack (unconsolidated). The sandpack does not employ a confining pressure, whereas the consolidated core does. The evolution of in-situ gas saturation vs. pressure is monitored in the sandpack using X-ray computed tomography. The two different porous media allow us to develop a mechanistic perspective whereby the effects of depletion rate and overburden pressure on heavy-oil solution gas drive are investigated. The results are striking. They show that the overburden pressure offsets partially the pore-pressure decline. This compaction, in turn, modifies the size and shape of mobile gas bubbles, and as a result the oil and gas relative permeabilies are greater within the confined, consolidated core. Additionally, the supersaturation in the sandpack is markedly larger, but recovery is greatest from the composite core at identical rates as a result of compaction. Introduction Solution gas drive in some heavy-oil reservoirs yields unexpectedly large oil recovery. Remarkably, the reservoir pressure declines more slowly than expected and the produced GOR increases slowly below the equilibrium bubblepoint pressure. Since 1988, when Smith identified the phenomenon (commonly referred to as foamy oil), experimental and theoretical studies have aimed to elucidate gas-flow and oil-production mechanisms. Results indicate that the factors governing the efficiency of heavy-oil solution gas drive are oil viscosity (Tang and Firoozabadi 2003, 2005), depletion rate (Tang et al. 2006; Kumar et al. 2000; Sahni et al. 2004), solution GOR (Tang and Firoozabadi 2003), oil composition (Tang et al. 2006; Bauger et al. 2001), and gas-bubble morphology (Li and Yortsos 1995; Tang et al. 2006). Obviously, these factors are not mutually exclusive. Among them, depletion rate as well as the size and shape of bubbles play a key role in recovery. Additionally, the oil composition is important because it plays a determining role in the flowing gas-bubble size that ultimately determines gas-phase mobility (Tang et al. 2006). Gas bubbles grow as a result of supersaturation (the difference between equilibrium and dynamic pressure) as well as pressure depletion. Gas-bubble nucleation is usually described as progressive or instantaneous (Li and Yortsos 1995; Firoozabadi and Kashchiev 1996), depending on the oil composition and porous medium (Tang et al. 2006; Kumar et al. 2000). Experiments with (El Yousfi et al. 1997; George et al. 2005) and simulation of (Arora and Kovscek 2003) gas nucleation in porous media indicate that the gas phase forms progressively. The period of active bubble nucleation is, however, relatively short compared to the time needed to deplete the sysem. Therefore, the process might be approximated as instantaneous nucleation if the longer time behavior is of interest (El Yousfi et al. 1997).
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Dong, Mingzhe, S. S. Sam Huang, and Keith Hutchence. "Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs." SPE Reservoir Evaluation & Engineering 9, no. 02 (April 1, 2006): 154–64. http://dx.doi.org/10.2118/88500-pa.
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Summary The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) scheme intended for application in some heavy-oil reservoirs after termination of either primary or waterflood production. The essence of the process is the restoration of the solution-gas-drive mechanism. The restoration is accomplished by reinjecting an appropriate amount of solution gas (mainly methane) and then repressuring the gas back into solution by injecting water until approximate original reservoir pressure is reached. This, aside from the replacement of produced oil by water, recreates the primary-production conditions. This novel recovery technique is being developed to target the considerable portion of heavy-oil resources located in thin reservoirs. Primary and secondary methods have managed to recover at best 10% of the initial oil in place (IOIP). Heat losses to overburden and underburden or bottomwater zones make thermal methods unsuitable for thin reservoirs. Sandpack-flood tests in 30.5-cm (length) × 5.0-cm (diameter) sandpacks were carried out for oils with a range of dead-oil viscosities from 1700 to 5400 mPa.s. The results showed that the pressure-cycling process could create a favorable condition for recharged gas to contact the remaining oil in reservoirs. This restores the situation whereby substantial amounts of gas are in solution for further "primary" production. The effects on the efficiency of the MPC process of cycle termination strategy, oil viscosity, and mobile-water saturation were investigated. Simulations were conducted to investigate the MPC process in three heavy-oil reservoirs in Saskatchewan, Canada. The effects on the process of infill wells, oil viscosity, gas-injection rate, and the presence of wormholes in reservoirs were studied. Introduction Heavy oil in thick-pay reservoirs (i.e., >10 m) is commonly produced with thermal-recovery methods. These methods (steam injection and its variants) are generally not suitable for thin reservoirs because of heat losses to overburden and underburden or bottomwater zones (Fairfield and White 1982; Dyer et al. 1994). The world's large untapped oil resource remaining after recovery by conventional technology offers potential for exploitation by a suitably developed tertiary-recovery technique. For example, Saskatchewan accounts for 62% of Canada's total heavy-oil resources (Bowers and Drummond 1997), including 1.7 billion m3 of proved reserves and 3.7 billion m3 of probable reserves (Saskatchewan Energy and Mines 1998). Of the province's proven initial heavy oil in place, 97% is contained in reservoirs where the pay zone is less than 10 m, and 55% in reservoirs with a pay zone less than 5 m thick (Huang et al. 1987; Srivastava et al. 1993). Primary and secondary methods combined recover, on average, only about 7% of the proven IOIP (Saskatchewan Energy and Mines 1998). The incentive is strong for the development of appropriate EOR techniques that will maximize the recovery potential of and profitability from these thin heavy-oil reservoirs. Extensive literature is available on CO2, flue gas, and produced-gas injection for heavy-oil recovery, including slug displacement, water alternating gas (WAG), and cyclic (huff ‘n’ puff) processes (Huang et al. 1987; Srivastava et al. 1993, 1994, 1999; Srivastava and Huang 1997; Ma and Youngren 1994; Issever et al. 1993; Olenick et al. 1992). A comparative study of the oil-recovery behavior for a 14.1°API heavy oil with different injection gases (CO2, flue gas, and produced gas) showed that CO2 was the best-suited gas for EOR of heavy oils (Srivastava et al. 1999). Cyclic CO2 injection for heavy-oil recovery was tested in the field, and field case histories indicated that oil production was enhanced (Olenick et al. 1992). However, natural CO2 sources are not available to most oil reservoirs. The cost of CO2 capture from flue gas and other sources may range from U.S. $25 to $70/ton (Padamsey and Railton 1993). Produced gas is available in large quantities at a much lower cost. With this consideration, produced gas can be an economically effective agent for heavy-oil recovery by the cyclic-injection process.
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Al-Wahaibi, Yahya Mansoor, Ann Helen Muggeridge, and Carlos Atilio Grattoni. "Experimental and Numerical Studies of Gas/Oil Multicontact Miscible Displacements in Homogeneous and Crossbedded Porous Media." SPE Journal 12, no. 01 (March 1, 2007): 62–76. http://dx.doi.org/10.2118/92887-pa.
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Summary We investigate oil recovery from multicontact miscible (MCM) gas injection into homogeneous and crossbedded porous media, using a combination of well-characterized laboratory experiments and detailed compositional flow simulation. All simulator input data, including most EOS parameters, were determined experimentally or from the literature produced fluids in all experiments were found not to be in compositional equilibrium. This was not predicted by the simulator, giving a poor match between experimental and simulated oil recoveries. The match was significantly improved for the cross-bedded displacements by using alpha factors derived from the MCM displacements in the homogeneous pack. Introduction The recovery of oil by miscible gas injection has been a subject of interest and research in petroleum engineering for more than 40 years (Stalkup 1983). In a first-contact, miscible (FCM) displacement, the gas and oil mix instantly in all proportions. No capillary forces exist, so, in principle, residual oil saturation is zero, and 100% oil recovery should be achieved. In practice, many phenomena conspire to limit the efficiency of the miscible flooding process, including viscous fingering, gravity override, and permeability heterogeneity. Moreover, it is often not economical, and sometimes not technically feasible, to inject a gas that is first-contact miscible with the oil. Instead, the injected gas is designed to develop miscibility with the oil by mass transfer during the displacement. This is a so-called MCM gas injection. If the bulk of the mass transfer is from the gas to the oil, then the displacement is termed a condensing drive. If most of the mass transfer is from the oil to the gas, then it is termed a vaporizing drive. In most cases, however, because of the multicomponent nature of oil and gas, the mass transfer is actually a mixture of both these cases, and the displacement is termed a condensing-vaporizing drive. Small-scale heterogeneities can have a significant impact on recovery efficiency (Jones et al. 1995; Jones et al. 1994; Kjonsvik et al. 1994), yet they cannot be modeled explicitly in field-scale simulations. Some of the most common small-scale heterogeneities found in sandstone reservoirs are laminations. However, because laminations have a small size and are generally at an angle to the principal flow direction, their influence onfluid flow is one of the most difficult features to predict numerically. There is a significant amount of literature describing systematic investigations of first-contact miscible and immiscible displacement processes in laminated sandstones (Huang et al. 1995, 1996; Ringrose et al. 1993; Kortekaas 1985; Honarpour et al. 1994; Hartkamp-Bakker 1991, 1993; McDougall and Sorbie 1993; Marcelle-DeSilva and Dawe 2003; Borresen and Graue 1996; Roti and Dawe 1993; Dawe et al. 1992; Caruana and Dawe 1996; Caruana 1997). Both experimental and simulation studies show that significant volumes of oil can be trapped by capillary forces during immiscible displacements (Huang et al. 1995, 1996; Ringrose et al. 1993; Kortekaas 1985; Honarpour et al. 1994; Hartkamp-Bakker 1991, 1993; McDougall and Sorbie 1993; Marcelle-DeSilva and Dawe 2003; Borresen and Graue 1996; Roti and Dawe 1993; Dawe et al. 1992; Caruana and Dawe 1996; Caruana 1997). However, the influence of these heterogeneities on MCM displacements, during which capillary forces change from being very significant when gas is first injected to negligible once miscibility has developed, has not yet been investigated. Indeed, the only comparisons of well-characterized MCM displacement experiments and detailed simulations reported in anywhere in the literature are those of Burger and colleagues (Burger and Mohanty 1997; Burger et al. 1996; Burger et al. 1994).
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Pozniak, H. "The energy transition: how to bridge the skills gap [oil&gas skills]." Engineering & Technology 16, no. 1 (February 1, 2021): 34–35. http://dx.doi.org/10.1049/et.2021.0105.
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Li, Kewen, Kevin Chow, and Roland N. Horne. "Influence of Initial Water Saturation on Recovery by Spontaneous Imbibition in Gas/Water/Rock Systems and the Calculation of Relative Permeability." SPE Reservoir Evaluation & Engineering 9, no. 04 (August 1, 2006): 295–301. http://dx.doi.org/10.2118/99329-pa.
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Summary It has been a challenge to understand why recovery by spontaneous imbibition could both increase and decrease with initial water saturation. To this end, mathematical models were developed with porosity, permeability, viscosity, relative permeability, capillary pressure, and initial water saturation included. These equations foresee that recovery and imbibition rate can increase, remain unchanged, or decrease with an increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to approximately 50%. The effects of initial water saturation on residual saturation, relative permeability, capillary pressure, imbibition rate, and recovery in gas/water/rock systems by cocurrent spontaneous imbibition were investigated both theoretically and experimentally. Water-phase relative permeabilities and capillary pressures were calculated with the experimental data of spontaneous imbibition. Experimental results in different rocks were compared. Introduction Spontaneous water imbibition is an important mechanism during water injection. Prediction of recovery and imbibition rate by spontaneous water imbibition is essential to evaluate the feasibility and the performance of water injection. For example, is water injection effective in the case of high initial water saturation in reservoirs? Answers to such a question may be found by investigating the effect of initial water saturation on spontaneous water imbibition. It has been observed experimentally that initial water saturation affects recovery and production rate significantly (Blair 1964; Zhou et al. 2000; Viksund et al. 1998; Cil et al. 1998; Tong et al. 2001; Li and Firoozabadi 2000; Akin et al. 2000). However, the experimental observations from different authors (Zhou et al. 2000; Cil et al. 1998; Li and Firoozabadi 2000; Akin et al. 2000) are not consistent. On the other hand, few studies have investigated the effect of initial water saturation on recovery and imbibition rate theoretically, especially in gas reservoirs. Using numerical-simulation techniques, Blair (1964) found that the quantity and the rate of oil produced after a given period of imbibition increased with a decrease in initial water saturation for countercurrent spontaneous imbibition. Zhou et al. (2000) found that both imbibition rate and final oil recovery in terms of oil originally in place (OOIP) increased with an increase in initial water saturation, whereas oil recovery by waterflooding decreased. Viksund et al. (1998) found that the final oil recovery (OOIP) by spontaneous water imbibition in Berea sandstone showed little variation with a change in initial water saturation from 0 to approximately 30%. For the chalk samples tested by Viksund et al. (1998), the imbibition rate first increased with an increase in initial water saturation and then decreased slightly as initial water saturation increased above 34%.Cil et al. (1998) reported that the oil recovery (in terms of recoverable oil reserves) for zero and 20% initial water saturation showed insignificant differences in behavior. However, the oil recovery for initial water saturation above 20% increased with an increase in initial water saturation. Li and Firoozabadi (2000) found that the final gas recovery in the units of gas originally in place (GOIP) by spontaneous imbibition decreased with an increase in initial water saturation in both gas/oil/rock and gas/water/rock systems. The imbibition rate (GOIP/min) increased with an increase in initial water saturation at early time but decreased at later time. Akin et al. (2000) found that the residual oil saturation was unaffected significantly by initial water saturation. In this study, equations, derived theoretically, were used to study the effect of initial water saturation on gas recovery and imbibition rate. The equations correlate recovery, imbibition rate, initial water saturation, rock/fluid properties, and other parameters. Experiments of spontaneous water imbibition in gas-saturated rocks were conducted to confirm the theoretical predictions. The effect of rock properties on gas recovery and imbibition rate was also studied. An X-ray CT scanner was used to monitor the distribution of the initial water saturation to confirm that the initial distribution of the water saturation was uniform. In this study, we only focused on cocurrent spontaneous imbibition. It was assumed that there were no chemical reactions or mass transfer between gas and liquid.
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Evans-Pughe, C. "Glorious mud [real-time mud-based bore-hole communication in oil and gas exploration]." Engineering & Technology 4, no. 6 (April 11, 2009): 74–75. http://dx.doi.org/10.1049/et.2009.0616.
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Tang, Guo-Qing, Yi Tak Leung, Louis M. Castanier, Akshay Sahni, Frederic Gadelle, Mridul Kumar, and Anthony R. Kovscek. "An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive." SPE Journal 11, no. 01 (March 1, 2006): 58–70. http://dx.doi.org/10.2118/84197-pa.
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Summary This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate. Introduction Solution gas drive has shown unexpectedly high recovery efficiency in some heavy-oil reservoirs. The mechanisms, however, that have been proposed are speculative, sometimes contradictory, and do not explain fully the origin of high primary oil recovery and slow decline in reservoir pressure. Smith (1988) first identified this effect. He hypothesized that gas bubbles smaller than pore constrictions are liberated from the oil, but are not able to form a continuous gas phase and flow freely. Instead, the gas bubbles exist in a dispersed state in the oil and only flow with the oil phase. Smith stated that oil viscosity is reduced significantly, resulting in high recovery performance. Later, many researchers focused on so-called foamy-oil behavior. Claridge and Prats (1995) hypothesized that heavy-oil components (such as asphaltenes) concentrate at the interfaces between oil and gas bubbles, thereby preventing bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be smaller than pore dimensions. Claridge and Prats stated that the concentration of heavy-oil components at the interfaces results in a reduction of the viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior of solution gas drive in heavy oils. Based on their studies, they found that dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high depletion rate. They stated that the main feature of the gas/oil dispersion is a reduced viscosity compared to the original oil. Models to explain the experimental results were also established (Sheng et al. 1994, 1996, 1999, 1995).
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Firoozabadi, Abbas, and Andrew Aronson. "Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media." SPE Reservoir Evaluation & Engineering 2, no. 06 (December 1, 1999): 550–57. http://dx.doi.org/10.2118/59255-pa.
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Summary In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil. Introduction Solution-gas drive is a basic recovery mechanism. The two parameters that affect the efficiency of this process are: critical gas saturation, and mobility of the gas and liquid phases. A high critical gas saturation implies a high recovery; a 30% critical gas saturation would result in 30% oil recovery provided the oil shrinkage is negligible. On the other hand, a low critical gas saturation does not necessarily imply a low recovery; a low gas mobility or a high liquid mobility would result in high recovery. Generally, solution-gas drive may not be efficient for very light oils. Factors which are believed to contribute to the low recovery are low critical gas saturation and high gas mobility. However, for a heavy oil, the recovery in solution-gas drive could be high either when the critical gas saturation is high or when the gas mobility is low and the liquid mobility is high. One purpose of this paper is to understand solution-gas drive for both light and heavy oils. Solution-gas drive is initiated with bubble nucleation, where at some critical supersaturation pressure (the pressure at which gas evolves from the supersaturated liquid) below the bubblepoint pressure, the formation of gas bubbles occurs. The bubbles may form instantaneously or according to the progressive nucleation theory.1 In progressive nucleation, the rate of bubble formation is related to the supersaturation. Recently, based on theoretical analysis, we have postulated that bubble nucleation in porous media can be an instantaneous nucleation process; all bubbles form instantaneously at the critical supersaturation pressure.1 Another objective of this work is to establish experimentally the instantaneous nature of nucleation in porous media. It has been known for some time that a number of heavy oil reservoirs in Canada (viscosity in the range of 200 to 20,000 cp) have high recovery efficiencies—around 15% to 20% by primary depletion.2,3 The high recovery occurs in the absence of gravity drainage and water drive. A number of authors have made attempts to explain the high recovery from heavy oil reservoirs. In an earlier paper, Smith2 hypothesized that solution-gas drive in heavy oil reservoirs is a two-phase flow, with the gas in the form of tiny bubbles moving with oil. Based on the work of Ward et al.,4 Smith argued that the radius of a stable bubble for a finite volume should be much smaller than the average pore throat. Ward et al.4 had estimated that for a bubble density of 103 cm3, the stable bubble may have a radius of 40 µm. These bubble densities and stable sizes may not apply to a heavy oil in porous media. Further theoretical work is needed to establish the bubble density and stable bubble size for heavy oils. In a later attempt, Islam and Chakma5 used both a long capillary tube and a horizontal core packed with unconsolidated sand to study mechanisms of bubble flow in heavy oil reservoirs. They used Dow Corning oils of 10, 1,000, and 5,000 cp viscosity and heavy oils to conduct flow experiments by simultaneous injection of gas bubbles and liquid. These experiments revealed that bubbles in a flowing stream of a viscous fluid will reduce the apparent viscosity. Islam and Chakma suggested a gas-oil relative permeability with a critical gas saturation of 40%. In-situ gas bubble formation and injection of gas bubbles in a liquid phase are fundamentally different processes. The work of these authors may not directly apply to solution-gas drive in heavy oil reservoirs. In a more recent study, Maini et al.,6 conducted many experiments using unconsolidated sand and heavy oils to study solution-gas drive. A 2-m long sand pack was employed by these authors. The recovery factor was obtained by dropping the pressure suddenly at the core outlet from a saturation pressure of some 700 psi to atmospheric pressure. More than 20% of the original heavy oil was produced in the primary depletion process. As has been observed by Islam and Chakma5 and others,1 a sudden drop in pressure may result in a higher recovery than a gradual pressure drop. From a number of tests, Maini et al. concluded that the critical gas saturation for the formation of a continuous gas phase could be about 40%. The critical gas saturation for heavy oils in the work of Islam and Chakma et al., and Maini et al., are much higher than the values for light oils.7 The above brief review reveals that further work is needed to understand the solution-gas drive in heavy oil reservoirs. The main objectives of this study are to: resolve the issue of very high critical gas saturations; find out whether tiny gas bubbles move with the oil phase; and determine the nature of bubble nucleation and bubble density and to better understand the efficiency of solution-gas drive for heavy oils in porous media. In this work, experiments with both light and heavy oils are performed in order to compare the solution-gas drive for light and heavy oils. A new visual coreholder is used to visually observe the appearance and flow of the gas phase. Experiment A schematic of the experimental apparatus is shown in Fig. 1. The setup, with slight differences, was used for the three sets of experiments. The main components of the apparatus include: the visual coreholder, a high pressure chromatography pump, pressure transducers, a system for providing a constant temperature of 77°F (±0.3°F) and a video recording system. The specially designed visual coreholder consists of an 8 in. long, 2 in. diameter Berea sandstone core (pore volume˜95 cm3, permeability˜500 md), capped at either end with a plexiglass cap (the top cap was machined with a dead end for trapping gas evolved from the core) and sealed with a heat-shrunk teflon sleeve. Surrounding the core is a water-filled translucent chamber, which is pressurized and acts as an overburden sleeve. Plumbed to the coreholder is a constant flow/pressure pump. The pump is used both for saturating the core system and for pressure decline through volume expansion.
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Lewis, Edward J., Eric Dao, and Kishore K. Mohanty. "Sweep Efficiency of Miscible Floods in a High-Pressure Quarter-Five-Spot Model." SPE Journal 13, no. 04 (December 1, 2008): 432–39. http://dx.doi.org/10.2118/102764-pa.
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Summary Evaluation and improvement of sweep efficiency are important for miscible displacement of medium-viscosity oils. A high-pressure quarter-five-spot cell was used to conduct multicontact miscible (MCM) water-alternating-gas (WAG) displacements at reservoir conditions. A dead reservoir oil (78 cp) was displaced by ethane. The minimum miscibility pressure (MMP) for ethane with the reservoir oil is approximately 4.14 MPa (600 psi). Gasflood followed by waterflood improves the oil recovery over waterflood alone in the quarter five-spot. As the pressure decreases, the gasflood oil recovery increases slightly in the pressure range of 4.550-9.514 MPa (660-1,380 psi) for this undersaturated viscous oil. WAG improves the sweep efficiency and oil recovery in the quarter five-spot over the continuous gas injection. WAG injection slows down gas breakthrough. A decrease in the solvent amount lowers the oil recovery in WAG floods, but significantly more oil can be recovered with just 0.1 pore volume (PV) solvent (and water) injection than with waterflood alone. Use of a horizontal production well lowers the sweep efficiency over the vertical production well during WAG injection. Sweep efficiency is higher for the nine-spot pattern than for the five-spot pattern during gas injection. Sweep efficiency during WAG injection increases with the WAG ratio in the five-spot model. Introduction As the light-oil reservoirs get depleted, there is increasing interest in producing more-viscous-oil reservoirs. Thermal techniques are appropriate for heavy-oil reservoirs. But gasflooding can play an important role in medium-viscosity-oil (30-300 cp) reservoirs and is the subject of this paper. Roughly 20 billion to 25 billion bbl of medium-weight- to heavy-weight-oil deposits are estimated in the North Slope of Alaska. Approximately 10 billion to 12 billion bbl exist in West Sak/Schrader Bluff formation alone (McGuire et al. 2005). Miscible gasflooding has been proved to be a cost-effective enhanced oil recovery technique. There are approximately 80 gasflooding projects (CO2, flue gas, and hydrocarbon gas) in the US and approximately 300,000 B/D is produced from gasflooding, mostly from light-oil reservoirs (Moritis 2004). The recovery efficiency [10-20% of the original oil in place (OOIP)] and solvent use (3-12 Mcf/bbl) need to be improved. The application of miscible and immiscible gasflooding needs to be extended to medium-viscosity-oil reservoirs. McGuire et al. (2005) have proposed an immiscible WAG flooding process, called viscosity-reduction WAG, for North Slope medium-visocisty oils. Many of these oils are depleted in their light-end hydrocarbons C7-C13. When a mixture of methane and natural gas liquid is injected, the ethane and components condense into the oil and decrease the viscosity of oil, making it easier for the water to displace the oil. From reservoir simulation, this process is estimated to enhance oil recovery compared to waterflood from 19 to 22% of the OOIP, which still leaves nearly 78% of the OOIP. Thus, further research should be directed at improving the recovery efficiency of these processes for viscous-oil reservoirs. Recovery efficiency depends on microscopic displacement efficiency and sweep efficiency. Microscopic displacement efficiency depends on pressure, (Dindoruk et al. 1992; Wang and Peck 2000) composition of the solvent and oil (Stalkup 1983; Zick 1986), and small-core-scale heterogeneity (Campbell and Orr 1985; Mohanty and Johnson 1993). Sweep efficiency of a miscible flood depends on mobility ratio (Habermann 1960; Mahaffey et al. 1966; Cinar et al. 2006), viscous-to-gravity ratio (Craig et al. 1957; Spivak 1974; Withjack and Akervoll 1988), transverse Peclet number (Pozzi and Blackwell 1963), well configuration, and reservoir heterogeneity, (Koval 1963; Fayers et al. 1992) in general. The effect of reservoir heterogeneity is difficult to study at the laboratory scale and is addressed mostly by simulation (Haajizadeh et al. 2000; Jackson et al. 1985). Most of the laboratory sweep-efficiency studies (Habermann 1960; Mahaffey et al. 1966; Jackson et al. 1985; Vives et al. 1999) have been conducted with first-contact fluids or immiscible fluids at ambient pressure/temperature and may not be able to respresent the displacement physics of multicontact fluids at reservoir conditions. In fact, four methods are proposed for sweep improvement in gasflooding: WAG (Lin and Poole 1991), foams (Shan and Rossen 2002), direct thickeners (Xu et al. 2003), and dynamic-profile control in wells (McGuire et al. 1998). To evaluate any sweep-improvement methods, one needs controlled field testing. Field tests generally are expensive and not very controlled; two different tests cannot be performed starting with identical initial states, and, thus, results are often inconclusive. Field-scale modeling of compositionally complex processes can be unreliable because of inadequate representation of heterogeneity and process complexity in existing numerical simulators. There is a need to conduct laboratory sweep-efficiency studies with the MCM fluids at reservoir conditions to evaluate various sweep-improvement techniques. Reservoir-conditions laboratory tests can be used to calibrate numerical simulators and evaluate qualitative changes in sweep efficiency. We have built a high-pressure quarter-five-spot model where reservoir-conditions multicontact WAG floods can be conducted and evaluated (Dao et al. 2005). The goal of this paper is to evaluate various WAG strategies for a model oil/multicontact solvent in this high-pressure laboratory cell. In the next section, we outline our experimental techniques. The results are summarized in the following section.
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Strekal, O. O. "THE FEATURES OF FINANCIAL CONTROL OF STATE-OWNED OIL AND GAS ENTERPRISES: MODERN UKRAINIAN EXPERIENCE." Ekonomické trendy 2, no. 2 (June 24, 2017): 28–31. http://dx.doi.org/10.24045/et.2017.2.5.
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Kürkçüoğlu, Mine, Hale Gamze Ağalar, Burak Temiz, Ahmet Duran, and Kemal Başer. "Chaerophyllum libanoticum Boiss. Et Kotschy: The fruit essential oil, composition, skin-whitening and antioxidant activities." European Journal of Life Sciences 1, no. 1 (April 29, 2022): 28–34. http://dx.doi.org/10.55971/ejls.1095855.
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This study was aimed to evaluate the essential oil composition of Chaerophyllum libanoticum fruits and its potential uses in the cosmetic industry. The essential oil was analyzed by Gas Chromatography (GC) and Gas Chromatography-Mass Spectrometry (GC/MS) systems, simultaneously. The yield of essential oil was calculated as 0.22 % (v/w). Major components of the oil were characterized as limonene (26.7%), p-cymene (25.5%), and β-phellandrene (7.0%). In addition, antioxidant and antityrosinase activities of the essential oil were evaluated. The oil exhibited moderate antioxidant activity (TEAC). In the DPPH assay, the oil was tested at 5 mg/mL concentration, and the inhibition ratio was calculated as 31.3 ± 1.1%. At 1 mg/mL of concentration, TEAC (mmol/L) value was determined as 0.027 ± 0.008. As evidence to its skin whitening properties, the oil inhibited the tyrosinase 17.7 ± 1.6 % at 1 mg/mL.
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Jessen, Kristian, and Franklin M. Orr. "On Interfacial-Tension Measurements to Estimate Minimum Miscibility Pressures." SPE Reservoir Evaluation & Engineering 11, no. 05 (October 1, 2008): 933–39. http://dx.doi.org/10.2118/110725-pa.
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Summary Measurements of the interfacial tension (IFT) of mixtures of a reservoir fluid and injection gas at various pressures have been proposed as an experimental method for predicting the minimum miscibility pressure (MMP) in an experiment referred to as the vanishing-IFT (VIT) technique. In this paper, we analyze the accuracy and reliability of the VIT approach using phase equilibrium and slimtube experimental observations and equation-of-state (EOS) calculations of the behavior of VIT experiments for the same systems. We consider 13 gas/oil systems for which phase equilibrium and density data and slimtube measurements of the MMP are available. We show that tuned EOS characterizations using 15 components to represent the gas/oil systems yield calculations of phase compositions and densities and calculated MMPs that reproduce the experimental observations accurately. We assume that IFTs can be calculated with a parachor expression, and we simulate the behavior of a series of VIT experiments with different mixture compositions in the VIT cell. We show that compositions of mixtures created in the VIT cell are not, in general, critical mixtures and that calculated estimates of the MMP obtained by the VIT approach depend strongly on the composition of the mixture used in the experiment. We show also that those MMP estimates may or may not differ significantly from values obtained in slimtube displacements. Fortuitously chosen mixture compositions can result in VIT-experiment estimates that agree well with slimtube MMPs, while for other mixtures, the error of the estimates can be quite large. In particular, we show that errors in the VIT-technique estimate of the MMP are often large for gas/oil systems for which the first-contact miscibility pressure (FCMP) is much larger than the slimtube MMP. We conclude, therefore, that the VIT experiment is not a reliable single source of information regarding the development of multicontact miscibility in multicomponent gas/oil displacements. Introduction Many oil fields are now candidates for enhanced-oil-recovery processes such as tertiary gasfloods or miscible water-alternating-gas injection schemes. The MMP is an important parameter in the design and implementation of these displacement processes and, hence, it is equally important that the MMP be determined by a method that is both reliable and accurate. Several methods have been proposed for measurement of the MMP. The slimtube-displacement experiment is the most commonly used approach (Yellig and Metcalfe 1980; Holm and Josendal 1982; Orr et al. 1982). Because of the time-consuming process of performing multiple slimtube-displacement experiments, alternative experimental approaches have been proposed. Some investigators have suggested use of a rising-bubble experiment, in which observations of bubbles of injection gas rising through oil (Christiansen and Haines 1987; Eakin and Mitch 1988; Novosad et al. 1990; Sibbald et al. 1991; Mihcakan and Poettmann 1994), are a basis of a method for determining the MMP. Zhou and Orr (1988) concluded that the changes in bubble behavior observed in the rising-bubble experiment are caused primarily by changes in IFT as components in the bubble dissolve in the oil and components in the oil transfer to the bubble. They showed that rising-bubble experiments could be used to measure the MMP for vaporizing gas drives, but are less accurate for condensing gas drives, while a drop of oil falling through gas could be used to determine the MMP for condensing gas drives. Whether either a falling-drop or a rising-bubble experiment could be used to determine the MMP accurately in condensing/vaporizing gas drives such as those described by Zick (1986), Stalkup (1987), and Johns et al. (1993) has not been determined. Rao and coworkers proposed a different use of IFT observations to determine the MMP (Rao 1997, 1999; Rao and Lee 2002, 2003; Ayirala et al. 2003; Ayirala and Rao 2004, 2006a, 2006b; Sequeira 2006). They measured IFTs for pendant drops of oil suspended in a cell containing a two-phase mixture of the injection gas and the oil. In that approach, known as the VIT experiment, the IFT is measured at a sequence of pressures, and the MMP is taken to be the pressure at which the IFT plotted as a function of pressure extrapolates to zero IFT. Orr and Jessen (2007) presented an analysis of the VIT technique based on EOS calculations for well-characterized ternary and quaternary gas/oil systems and demonstrated that the VIT experiment may give estimates of the MMP that differ significantly from the MMP based on critical tie-lines for condensing, vaporizing, and condensing/vaporizing gas drives. In this paper, we extend the analysis of Orr and Jessen (2007) and calculate the IFT behavior that would be observed in the VIT experiment for gas displacements of multicomponent crude-oil systems. We assess the accuracy of MMP estimated by the VIT approach for 13 multicomponent gas/oil displacements for which experimental phase-equilibrium and slimtube data are available, and we demonstrate that for these multicomponent crude-oil systems, the VIT approach can give estimates of the MMP that are close to the actual MMP or that are significantly in error, depending on the compositions of mixtures created in the equilibrium cell.
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Egermann, Patrick, Michel Robin, Jean-Marc N. Lombard, Cyrus A. Modavi, and Mohammed Z. Kalam. "Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 621–29. http://dx.doi.org/10.2118/81577-pa.
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Summary Secondary- and tertiary-recovery processes based on gas injection can extend the life of waterflooded reservoirs by maximizing the oil recovery. However, the injection strategy needs to be studied carefully to optimize the overall sweep efficiency. In particular, the impact of possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection, and a simultaneous water-alternating-gas (SWAG) injection. The experiments were carried out on composite cores consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were monitored continually during the hydrocarbon recovery, including the chromatographic analysis of the produced gas. The final oil recovery resulting from the three types of experiments was very good [approximately 90% original oil in place (OOIP) at surface conditions after 6 pore-volume (PV) injection] and quite similar within the expected experimental error, regardless of the sequence of gas injection. The low remaining oil saturation (ROS) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Because of the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by mobility control of the water phase. This enhances the sweep efficiency by viscous drive. A water-blocking effect was found to be negligible because it could be anticipated due to wettability consideration. The influence of the fluid description (equation of state, or EOS) and the three-phase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained with both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with seven pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model (either "geometrical construction" or Stone1) on the results was found to be small. Introduction For enhanced oil recovery (EOR) purposes, miscible or immiscible hydrocarbon gas injections have been applied successfully in many oil reservoirs throughout the world (Thomas et al. 1994; Lee et al. 1988). Compared to water injection, gas injection is associated with higher microscopic displacement efficiency due to the low value of the interfacial tension (IFT) between the oil and gas phases. IFT tends toward zero when miscibility is reached, which means that the oil recovery can be total in the swept area. Even when miscibility is not reached, the mass-transfer mechanisms that occur between oil and gas phases lead to low IFT values when compared to waterflooding. Even under those conditions, regarding remaining oil-saturation values, gas injection appears to be an interesting recovery process.
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Rihani, Rachida, and Mouna Ayyach. "Traitement d'une eau de bourbier des puits de forage de Hassi-Messaoud." Journal of Renewable Energies 6, no. 2 (December 31, 2003): 95–100. http://dx.doi.org/10.54966/jreen.v6i2.964.
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L'étude consiste à réaliser un procédé de traitement biologique d'une eau de bourbier des puits de forage de Hassi-Messaoud contenant des concentrations excessives en plomb et en gas-oil. Le traitement est effectué au moyen d'un bioréacteur à l'intérieur duquel est entassé un garnissage solide inerte connu sous le nom commercial de " Siporex ".Afin d'évaluer l'effet inhibiteur du plomb sur le processus de biodégradation de la matière organique et du gas-oil, nous avons procédé à une variation croissante de la charge en plomb (5, 15 et 80 mg/l). Ainsi, l'expérience menée a permis la détermination de la charge donnant le meilleur rendement Par ailleurs, une analyse microbiologique a été effectuée afin d'identifier les souches microbiennes présentes dans l'eau d'ensemencement et dans l'eau des deux colonnes.
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Bertrand, Rudolf. "Maturation thermique et histoire de l'enfouissement et de la génération des hydrocarbures du bassin de l'archipel de Mingan et de l'île d'Anticosti, Canada." Canadian Journal of Earth Sciences 27, no. 6 (June 1, 1990): 731–41. http://dx.doi.org/10.1139/e90-075.
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Carbonate platform sequences of Anticosti Island and the Mingan Archipelago are Early Ordovician to Early Silurian in age. With the exception of the Macasty Formation, the sequences are impoverished in dispersed organic matter, which is chiefly composed of zooclasts. Zooclast reflectances suggest that the Upper Ordovician and Silurian sequences outcropping on Anticosti Island are entirely in the oil window but that the Lower to Middle Ordovician beds of the Mingan Archipelago and their stratigraphic equivalents in the subsurface of most of Anticosti Island belong to the condensate zone. Only the deeper sequences of the southwestern sector of Anticosti Island are in the diagenetic dry-gas zone. The maximum depth of burial of sequences below now-eroded Silurian to Devonian strata increases from 2.3 km on southwestern Anticosti Island to 4.5 km in the Mingan Archipelago. A late upwarp of the Precambrian basement likely allowed deeper erosion of the Paleozoic strata in the vicinity of the Mingan Archipelago than on Anticosti Island. Differential erosion resulted in a southwestern tilting of equal maturation surfaces. The Macasty Formation, the only source rock of the basin (total organic carbon generally > 3.5%, shows a wide range of thermal maturation levels (potential oil window to diagenetic dry gas). It can be inferred from the burial history of Anticosti Island sequences that oil generation began later but continued for a longer period of geologic time in the northeastern part than in the southeastern part of the island. Oil generation was entirely pre-Acadian in the southern and western parts of Anticosti Island, but pre- and post-Acadian in the northern and eastern parts.
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Mamedov, R. A., M. A. Allanazarova, R. R. Sagdeev, and T. N. Suyunbaev. "Formation conditions and evolution of the oil and gas strata of the prospective East Siberian oil and gas province." Proceedings of higher educational establishments. Geology and Exploration, no. 1 (June 22, 2022): 38–49. http://dx.doi.org/10.32454/0016-7762-2022-64-1-38-49.
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Introduction. East Siberian Sea shelf refers to the Novosibirsk-Chukotka prospective oil and gas province. The definition of the East Siberian shelf as a prospective oil and gas province and its division into areas is based, along with the structural and geological prerequisites, on the identification of numerous bitumen occurrences in the Paleozoic, Triassic and Jurassic sediments of the Novosibirsk Islands.Aim. To construct spatio-temporal digital models of sedimentary basins and hydrocarbon systems for the main horizons of source rocks, as well as to carry out their detailed analysis based on the available information about the oil and gas content, the gas-chemical composition of sediments, the characteristics of the component composition and evolution of source rocks within the studied prospective oil and gas province. The conducted research made it possible to study regional trends in oil and gas content, features of the sedimentary cover formation and the development of hydrocarbon systems in the area under study.Materials and methods. The materials of production reports obtained for individual large objects in the water area were the source of information. A basin analysis was based on a model developed by the Equinor specialists (Somme et al., 2018) [8, 9], which covered the time period from the Triassic to Paleogene inclusive and took into account the plate-tectonic reconstructions performed by Dor’e et al. in 2015. The resulting model included four main sedimentary complexes: pre-Aptian, Apt-Upper Cretaceous, Paleogene, and Neogene-Quaternary.Results. The calculation of numerical models was carried out in two versions with different types of kerogen of oil and gas source strata corresponding to humic and sapropel organic matter. The key factor in controlling the development of hydrocarbon systems was found to be the sinking rate of the basins and the thickness of the formed overburden complexes.Conclusion. The conducted analysis allowed the most promising research objects to be identified. The main foci of hydrocarbon generation in the Aptian-Late Cretaceous and Paleogene complexes were identified, along with the area of their most probable accumulation. Significant hydrocarbon potential is expected in the Paleogene clinoforms of the Eastern Arctic. This complex is currently underestimated, thus requiring further resource assessment study. A detailed mapping of its interior structure should be carried out.
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Wylie, Philip L., and Kishore K. Mohanty. "Effect of Wettability on Oil Recovery by Near-Miscible Gas Injection." SPE Reservoir Evaluation & Engineering 2, no. 06 (December 1, 1999): 558–64. http://dx.doi.org/10.2118/59476-pa.
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Summary Oil can become bypassed during gas injection as a result of gravitational, viscous, and heterogeneity effects. Mass transfer from the bypassed region to the flowing gas is dependent upon pressure-driven, gravity-driven, and capillary-driven crossflows as well as diffusion and dispersion. The focus of this study is on the influence that wettability has on bypassing and mass transfer. Experimental results reveal comparatively less bypassing occurs in a strongly oil-wet sandstone than in a water-wet sandstone for gravity-dominated, secondary gas floods. Mass transfer under oil-wet conditions is enhanced, as a result of oil-wetting film connectivity, over that of water-wet conditions, where water shielding is significant. Introduction As gas flooding becomes a more viable means of enhanced oil recovery, the ability to quantify and simulate bypassing and mass transfer becomes increasingly important. Bypassing in gas injection processes may occur as a result of gravity override, viscous fingering, or heterogeneities in the reservoir, such as low permeability layers or a fracture-matrix network. Mass-transfer mechanisms, such as pressure-driven, gravity-driven, capillary-driven, and diffusion/dispersion crossflows are studied on the laboratory scale before being scaled up for incorporation into reservoir simulations. The laboratory studies reveal influences that govern the extent that each mechanism contributes to overall mass transfer. The enrichment of the injected gas has been discovered, through simulation and experiment, to play a key role in overall gas flood performance.1–6 Pande2 proposed, using 1D numerical simulation, that secondary and tertiary hydrocarbon gas floods, at or below minimum miscibility pressure or enrichment (MMP or MME), may perform as well as enriched gas floods. Shyeh-Yung1 demonstrated that tertiary gasflood recoveries below MMP do not decrease as severely as predicted by slim-tube tests for CO2 and Shyeh-Yung and Stadler5 and Grigg et al.7 showed that gasflood Sorm increases almost linearly as hydrocarbon gas enrichment decreases. The injection methodology has been shown to affect ultimate oil recovery.7,8 The experiments of Jackson et al.7 demonstrated that the optimum miscible WAG ratio in a water-wet bead pack under tertiary conditions was 0:1 (continuous gas injection) and 1:1 for a miscible flood in an oil-wet bead pack. Laboratory studies have also revealed the influence of mass-transfer zone orientation and water saturation on gasflood oil recovery.9–11 Burger et al.9,10 have found that mass transfer increases with solvent enrichment and that horizontal mass transfer provides the most efficient oil recovery as a result of gravity-driven crossflow. The inverted, or positive gravity orientation, exhibits countercurrent gravity-driven crossflow that inhibits mass transfer somewhat. The vertical, or negative gravity orientation, yielded the lowest recovery, as diffusion was the only significant mass-transfer mechanism for their particular fluid system. Wylie and Mohanty11 have investigated the effect of water saturation on bypassing and mass transfer, concluding that mass transfer is decreased in the presence of water, but that capillary forces become more dominant as enrichment decreases. Less bypassing, due to gravity override, was observed in horizontal gasflood experiments in the presence of water; however, it was conjectured that bypassing was still present as a result of fluid redistribution and water shielding. With the exception of Jackson et al.7 these studies were performed under strongly water-wet or at restored mixed-wet conditions. The extent that media wettability influences gasflood bypassing and the subsequent mass transfer is largely unexplored. Recent research has examined wettability alteration and its influence on waterflood oil recoveries.12,13 Buckley et al.12 concluded that high pH, low ionic strength, monovalent salt solutions typically induce more water-wet conditions on silica surfaces or cores, aged with asphaltic crude oils, while lower pH solutions led to less water wettability. Their results showed optimum waterflood oil recoveries from Clashach cores under mixed-wet conditions with a slightly positive Amott index. Tang and Morrow13 investigated the influences that temperature, salinity, and oil composition have on wettability and waterflood oil recovery from cores aged in crude oil. They discovered wettability to shift toward more water-wet conditions and waterflood oil recovery to increase with a decrease in the salinity of the connate or invading brine. Waterflood oil recoveries also increased as the displacement temperature increased. Basu and Sharma14 provided evidence suggesting that mixed wettability results from the capillarity-induced, destabilization of brine films on the rock surface.
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Rahma, Fatimah Aulia. "The Correlation Between Psychological Well-Being and Work Engagement on Female Employees in Oil and Gas Industry." FENOMENA 31, no. 1 (June 30, 2022): 1–11. http://dx.doi.org/10.30996/fn.v31i1.8194.
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This research aimed to examine the correlation between psychological well-being with work engagement and involved 73 female employee at ‘X’ Oil and Gas Company. Data collected using survey method on the application Indonesian Language and Cultural Adaptation of Psychological Wellbeing Scale result of a translation by (Rachmayani et al., 2017) and work engagement scale which consists of 9 items and is the result of a translation by (Kristiana et al., 2018) used to measure whole work engagement on female employee in this research. . The sampling technique used in this study was total sampling. The results of this research showed that there was a correlation between autonomy dimension (psychological well-being) (p=<0,01; r=-0,298), environmental mastery dimension (psychological well-being) with work engagement (p=<0,04; r=-0,33), and there was no correlation between psychological well-being and work engagement on female employee at ‘X’ Oil and Gas Company (p=<0,425; r=-0,095).
psychological well-being, work engagement, oil and gas
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Adewuyi, Adeolu Olusegun, Olusegun S. Adeboye, and Aviral Kumar Tiwari. "A New Look at the Connectedness Between Energy and Metal Markets Using a Novel Approach." American Business Review 27, no. 1 (May 2024): 116–66. http://dx.doi.org/10.37625/abr.27.1.116-166.
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This study extends the existing literature in this area by examining the conditional connectedness between energy and metal markets using a novel time-varying quantile and frequency connectedness method developed by Chatziantoniou, et al. (2022) based on Ando, et al. (2018) and Barunik & Krehlik (2018) techniques. Connectedness between the markets was analyzed across various times and frequencies, with daily data covering May 18, 2011, to September 23, 2020. Short-term dynamics strongly drive the total pairwise shocks, while the contribution of medium-term dynamics was meagre, and that of long-term dynamics was insignificant. While the natural gas, gasoline, gas oil, heating oil, crude oil, coal, kerosene, propane, and diesel markets spilled-out shocks to many markets, gold, copper, aluminum, platinum, silver, nickel, palladium and lead markets received shocks from many markets. Zinc appears as an isolated market. The market which influenced the majority of other markets is natural gas, followed by gasoline, gas oil, heating oil, crude oil, coal, kerosene, propane and diesel. In contrast, zinc did not influence any of the markets. The pairwise connectedness results reveal the existence of intra-market linkages within the energy markets (horizontal market integration), while inter-market associations also exist between energy and metal markets (vertical market integration). However, there are only intra-market linkages in the metal markets. Linkages are strong in some markets during the COVID-19 crisis. These results inform some policy recommendations well-articulated in the conclusion section.
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Wang, Ruihe, Zhangxin Chen, Jishun Qin, and Ming Zhao. "Performance of Drainage Experiments With Orinoco Belt Heavy Oil in a Long Laboratory Core in Simulated Reservoir Conditions." SPE Journal 13, no. 04 (December 1, 2008): 474–79. http://dx.doi.org/10.2118/104377-pa.
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Summary When some heavy-oil reservoirs are produced using gas drive, they show three important features: low production gas/oil ratios, higher-than-expected production rates, and relatively high oil recovery. The mechanism for this unusual behavior remains controversial and poorly understood, though the term "foamy oil" is often used to describe such behavior. The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. There exist nearly one trillion bbl of heavy oil (oil in place) in this region on the basis of a recent evaluation. Two crucial issues must be addressed before or during designing production projects: What is a suitable method for evaluating the foamy-oil drive mechanism that plays a major role during such oil recovery, and how do we obtain a reasonable percentage of ultimate oil recovery? Unfortunately, it is still difficult to give good explanations for these two issues, although several studies were performed. This paper attempts to present better explanations for these two issues using experimental drainage in a long laboratory core in simulated reservoir conditions. Our experiments show that ultimate oil recovery for the heavy oil in the Orinoco belt can be as high as 15-20%. This high recovery comes from three contributions: fluid and rock expansion, foamy-oil drive, and conventional-solution-gas drive. Approximately 3-5% of recovery is from fluid and rock expansion, 11-16% from foamy-oil drive, and 2-4% from conventional-solution-gas drive. This ultimate-oil-recovery percentage is much higher than the 12% that has been used in the field-development plan for the Orimulsion project. The experiments performed and their findings obtained in this paper are representative at least in the Orinoco belt region. Introduction Most practitioners try to produce as much oil as possible under primary recovery. In all solution-gas-drive reservoirs, gas is released from solution as the reservoir pressure declines. Gas initially exists in the form of small bubbles created within individual pores. As time evolves and pressure continues to decline, these bubbles grow to occupy the pores. With a further decline in pressure, the bubbles created in different locations become large enough to coalesce into a continuous gas phase. Conventional wisdom indicates that the discrete bubbles that are larger than pore throats remain immobile (trapped by capillary forces) and that gas flows only after the bubbles have coalesced into a continuous gas phase. Once the gas phase becomes continuous, which is equivalent to the gas saturation becoming larger than critical, the minimum saturation at which a continuous gas phase exists in porous media (Chen et al. 2006), traditional two-phase (gas and oil) flow with classical relative permeabilities occurs. A result of this evolution process is that the production gas/oil ratio (GOR) increases rapidly after the critical gas saturation has been exceeded. Field observations in some heavy-oil reservoirs, however, do not fit into this solution-gas-drive description in that the production GOR remains relatively low. The recovery factors (percentage of the oil in a reservoir that can be recovered) in such reservoirs are also unexpectedly high. A simple explanation of these observations could be that the critical gas saturation is high in these reservoirs. This explanation cannot be confirmed by direct laboratory measurement of the critical gas saturation. An alternative explanation of the observed GOR behavior is that gas, instead of flowing only as a continuous phase, also flows in the form of gas-in-oil dispersion. This type of dispersed gas/oil flow is what is referred to as "foamy-oil" flow. Although the unusual production behavior in some heavy-oil reservoirs was observed as early as the late 1960s, Smith (1988) appears to have been the first to report it and used the terms "oil/gas combination" and "mixed fluid" to describe the mixture of oil and gas that is entrained in heavy oil as very tiny bubbles. Baibakov and Garushev (1989) used the term "viscous-elastic system" to describe highly viscous oil with very fine bubbles present. Sarma and Maini (1992) were the first to use the phrase "foamy oil" to describe viscous oil that contains dispersed gas bubbles. Claridge and Prats (1995) used the terms "foamy heavy oil" and "foamy crude." Although there is continuing debate on the suitability of the term "foamy-oil flow" to describe the anomalous flow of the oil/gas mixture in primary production of heavy oil (Firoozabadi 2001; Tang and Firoozabadi 2003; Tang and Firoozabadi 2005), this expression has become a fixture in the petroleum-engineering terminology (Chen 2006, Maini 1996). The actual structure of foamy-oil flow and its mathematical description are still not well understood. Much of the earlier discussion of such flow was based on the concept of microbubbles [i.e., bubbles much smaller than the average pore-throat size and, thus, free to move with the oil during flow (Sheng et al. 1999)]. This type of dispersion can be produced only by nucleation of a very large number of bubbles (explosive nucleation) and by the presence of a mechanism that prevents these bubbles from growing into larger bubbles with decline in pressure (Maini 1996). This hypothesis has not been supported by experimental evidence. A more plausible hypothesis on the structure of foamy-oil flow is that it involves much larger bubbles migrating with the oil and that the dispersion is created by the breakup of bubbles during their migration with the oil. The major difference between the conventional-solution-gas drive and the foamy-solution-gas drive is that the pressure gradient in the latter is strong enough to mobilize gas clusters after they have grown to a certain size. Maini (1999) presented experimental evidence that supports this hypothesis for foamy-oil flow. This hypothesis seems consistent with the visual observations in micromodels that show the bubble size to be larger than the pore size. However, more laboratory experiments must be conducted to validate this hypothesis. The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. The largest heavy-oil reserves in the world are in this region, with nearly one trillion bbbl of heavy oil in place on the basis of a recent evaluation (Fig. 1) (Andarcia et al. 2001). The unusual recovery performance mentioned previously has been observed during drainage of heavy-oil reservoirs in the Orinoco belt. The problems we now face are the following. How will we estimate the production performance for the present project by taking into account the foamy-oil-drive mechanism? In addition, what will be an applicable measure to evaluate the production potential of this project? What will a production profile of this project look like? How much oil will be produced within a certain time period of our operation? Unfortunately, there were no satisfactory answers yet for these questions. This paper attempts to address these issues using results from a suite of laboratory experiments. The attempts to address these issues will improve our understanding of foamy-oil behavior and its mechanism.
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Kantzas, Apostolos, Minghua Ding, and Jong Lee. "Residual Gas Saturation Revisited." SPE Reservoir Evaluation & Engineering 4, no. 06 (December 1, 2001): 467–76. http://dx.doi.org/10.2118/75116-pa.
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Summary The determination of residual gas saturation in gas reservoirs from long spontaneous and forced-imbibition tests is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will lead to forced imbibition in areas of high drawdown and spontaneous imbibition in areas of low drawdown. It is further assumed that in the bulk of the reservoir, spontaneous imbibition will prevail and the reservoir will be water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. A series of experiments is presented in which it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. It was found, in some cases, that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water pull by imbibition). It is expected that this work will shed some new light on an old, but not-so-well-understood, topic. Introduction When a porous medium is partially or fully saturated with a nonwetting phase, and a wetting phase is allowed to invade the porous medium, the process is called imbibition. For the problem addressed in this work, the nonwetting phase is assumed to be gas, and the wetting phase is assumed to be the aquifer water. If the medium is dry and the water is imbibing, then the imbibition is primary (Swi=0). If the water is already in the medium, the imbibition is secondary (Swi>0). If there is no driving force other than the affinity to wet, the imbibition is spontaneous. If there is any other positive pressure gradient, the imbibition is called forced. Numerous papers have been written on the subject of residual oil saturation from imbibition, but fewer have been prepared on the subject of residual gas saturation from imbibition. The common perception is that many of the principles that cover oil and gas reservoirs are the same. Agarwal1 addressed the relationship between initial and final gas saturation from an empirical perspective. He worked with 320 imbibition experiments and segmented the database to develop curve fits for common rock classifications. Land2 noted that available data seemed to fit very well to an empirical functional form given asEquation 1 In this model, the only free parameter is the maximum observable trapped nonwetting phase saturation corresponding to Sgr (Sgi=1). This expression does not predict residual phase saturation, only how residual saturation scales with initial saturation. Zhou et al.3 studied the effect of wettability, initial water saturation, and aging time on oil recovery by spontaneous imbibition and waterflooding. A correlation between water wetness and oil recovery by waterflooding and spontaneous imbibition was observed. Geffen et al.4 investigated some factors that affect the residual gas saturation, such as flooding rate, static pressure, temperature, sample size, and saturation conditions before flooding. They found that water imbibition on dry-plug experiments was different from waterflooding experiments with connate water. However, they concluded that the residual gas saturation from the two types of experiments was essentially the same. Keelan and Pugh5 concluded that trapped gas saturation existed after gas displacement by wetting-phase imbibition in carbonate reservoirs. Their experiments showed that the trapped gas varied with initial gas in place and that it was a function of rock type. Fishlock et al.6 investigated the residual gas saturation as a function of pressure. They focused on the mobilization of residual gas by blowdown. Apparently, the trapped gas did not become mobile immediately as it expanded. The gas saturation had to increase appreciably to a critical value for gas remobilization. Tang and Morrow7 introduced the effect of composition on the microscopic displacement efficiency of oil recovery by waterflooding and spontaneous imbibition. They concluded that the cation valency was important to crude/oil/rock interactions. Chierici et al.8 tested whether a reliable value of reserves could be obtained from reservoir past-production performance by analyzing results from six gasfield experiments. They concluded that different gas reservoir aquifer systems could show the same pressure performance in response to a given production schedule. Baldwin and Spinler9 investigated residual oil saturation starting from different initial water saturation using magnetic resonance imaging (MRI). They concluded that at low initial water saturation, the presence of a significant waterfront during spontaneous water imbibition indicated that the rate of water transport was less than that of oil. At high initial water saturation, the more uniform saturation change during spontaneous water imbibition indicated that the rate of water transport was greater than that of oil. The pattern of spontaneous imbibition depended on sample wettability, with less effect from frontal movement in less water-wet samples. Pow et al.10 addressed the imbibition of water in fractured gas reservoirs. Field and laboratory information suggested that a large amount of gas was trapped through fast water imbibition through the fractures and premature water breakthrough. The postulation was made that such gas reservoirs would produce this gas if and when the bypassed gas was allowed to flow to the production intervals under capillary-controlled action. The question of whether the rate of imbibition could enhance the production of this trapped gas was raised. Preliminary experiments on full-diameter core pieces showed that the rates of imbibition were extremely slow and that if the different imbibition experiments were performed in full-diameter plugs, the duration of the experiments would be prohibitively long. These experiments formulated the experimental strategy presented in the following sections.
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Boone, Jeff P. "Revisiting the Reportedly Weak Value Relevance of Oil and Gas Asset Present Values: The Roles of Measurement Error, Model Misspecification, and Time-Period Idiosyncrasy." Accounting Review 77, no. 1 (January 1, 2002): 73–106. http://dx.doi.org/10.2308/accr.2002.77.1.73.
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This paper investigates three potential explanations for the puzzlingly weak value relevance of oil and gas asset present values documented in prior research: measurement error, model misspecification, and time-period idiosyncrasy. I operationally define the magnitude of measurement error as the measurement error variance, estimated using an errors-in-variables two-stage regression model similar to that used by Barth (1991) and Choi et al. (1997). I find that (1) measurement error in the present value measure of oil and gas assets is on average less than the measurement error in the historical cost asset measure; (2) oil and gas assets measured at present value explain significantly more across-firm and across-time variation in stock prices than do oil and gas assets measured at historical cost; and (3) model misspecification partially accounts for the puzzlingly weak reported value relevance of the present value measure in prior research.
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Koning, Tako, Nick Cameron, and John Clure. "Undiscovered Potential in the Basement Exploring in Sumatra for oil and gas in naturally fractured and weathered basement reservoirs." Berita Sedimentologi 47, no. 2 (October 2, 2021): 67–79. http://dx.doi.org/10.51835/bsed.2021.47.2.320.
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This paper was first published in GEOExPro magazine, Vol. 18, No. 1, 2021, both in print and electronically (Koning et al., 2021) and is republished with permission from GEOExPro. For Berita Sedimentologi we have made various changes to the existing text and figures by including further results from our ongoing in-depth research into the geology of basement oil and gas plays in Sumatra.This paper provides and up-to-date and in-depth review of the status of exploration for oil and gas in naturally fractured and weathered basement throughout Sumatra. Also reviewed is the status of oil and gas production from Sumatra’s basement fields. In this paper’s section on Economic Impact, we emphasize the major positive contribution to Indonesia’s economy resulting from gas produced from basement reservoirs in the South Sumatra Basin.
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Chen, Zhangxin, Jian Sun, Ruihe Wang, and Xiaodong Wu. "A Pseudobubblepoint Model and Its Simulation for Foamy Oil in Porous Media." SPE Journal 20, no. 02 (July 31, 2014): 239–47. http://dx.doi.org/10.2118/172345-pa.
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Summary This is the second paper of a series in which we study heavy oil in porous media. The first paper dealt with an experimental study (Wang et al. 2008), whereas a mathematical and simulation study is presented here. The research program stems from the need to predict the field performance of a class of heavy-foamy-oil reservoirs. These reservoirs show a better-than-expected primary performance: lower production gas/oil ratios (GORs), higher-than-expected production rates, and higher oil recovery. A mechanism used to account for the observed performance is that the liberated solution gas is entrained in the oil when the reservoir pressure falls below the thermodynamic equilibrium bubblepoint pressure. The presence of entrained gas increases the effective compressibility of the oil phase and prevents gas from becoming a free phase. Hence, the foamy oil behaves as if it had a pseudobubblepoint pressure below the usual equilibrium bubblepoint pressure. This paper describes a pseudobubblepoint model and a methodology that can be used to compute foamy-oil fluid properties from conventional laboratory pressure/volume/temperature (PVT) data. The techniques developed are then used to study foamy oil in the Orinoco belt, Venezuela. The present mathematical model is validated by comparing numerical and experimental results.
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Huh, Chun, and William R. Rossen. "Approximate Pore-Level Modeling for Apparent Viscosity of Polymer-Enhanced Foam in Porous Media." SPE Journal 13, no. 01 (March 1, 2008): 17–25. http://dx.doi.org/10.2118/99653-pa.
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Summary Foam is used in the oil industry in a variety of applications, and polymer is sometimes added to increase foam's stability and effectiveness. A variety of surfactant and polymer combinations have been employed to generate polymer-enhanced foam (PEF), typically anionic surfactants and anionic polymers, to reduce their adsorption in reservoir rock. While addition of polymer to bulk foam is known to increase its viscosity and apparent stability, polymer addition to foams for use in porous media has not been as effective. In this pore-level modeling study, we develop an apparent viscosity expression for PEF at fixed bubble size, as a preliminary step to interpret the available laboratory coreflood data. To derive the apparent viscosity, the pressure-drop calculation of Hirasaki and Lawson (1985) for gas bubbles in a circular tube is extended to include the effects of shear-thinning polymer in water, employing the Bretherton's asymptotic matching technique. For polymer rheology, the Ellis model is employed, which predicts a limiting Newtonian viscosity at the low-shear limit and the well-known power-law relation at high shear rates. While the pressure drop caused by foam can be characterized fully with only the capillary number for Newtonian liquid, the shear-thinning liquid requires one additional grouping of the Ellis-model parameters and bubble velocity. The model predicts that the apparent viscosity for PEF shows behavior more shear-thinning than that for polymer-free foam, because the polymer solution being displaced by gas bubbles in pores tends to experience a high shear rate. Foam apparent viscosity scales with gas velocity (Ug) with an exponent [-a/(a+2)], where a, the Ellis-model exponent, is greater than 1 for shear-thinning fluids. With a Newtonian fluid, for which a = 1, foam apparent viscosity is proportional to the (-1/3) power of Ug, as derived by Hirasaki and Lawson. A simplified capillary-bundle model study shows that the thin-film flow around a moving foam bubble is generally in the high-shear, power-law regime. Because the flow of polymer solution in narrower, water-filled tubes is also governed by shear-thinning rheology, it affects foam mobility as revealed by plot of pressure gradient as a function of water and gas superficial velocities. The relation between the rheology of the liquid phase and that of the foam is not simple, however. The apparent rheology of the foam depends on the rheology of the liquid, the trapping and mobilization of gas as a function of pressure gradient, and capillary pressure, which affects the apparent viscosity of the flowing gas even at fixed bubble size. Introduction When a gas such as CO2 or N2 is injected into a mature oil reservoir for improved oil recovery, its sweep efficiency is usually very poor because of gravity segregation, reservoir heterogeneity, and viscous fingering of gas, and foam is employed to improve sweep efficiency with better mobility control (Shi and Rossen 1998; Zeilinger et al. 1996). When oil is produced from a thin oil reservoir overlain with a gas zone, a rapid coning of gas can drastically reduce oil production rate, and foam is used to delay the gas coning (Aarra et al. 1997; Chukwueke et al. 1998; Dalland and Hanssen 1997; Thach et al. 1996). During a well stimulation operation with acid, a selective placement of acid into a low-permeability zone from which oil has not been swept is desired, which can be accomplished with use of foam (Cheng et al. 2002). For environmental remediation of subsurface soil using surfactant, foam is used to improve displacement of contaminant, such as DNAPL, from heterogeneous soil (Mamun et al. 2002).
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Omara, Mark, Ritesh Gautam, Madeleine A. O'Brien, Anthony Himmelberger, Alex Franco, Kelsey Meisenhelder, Grace Hauser, et al. "Developing a spatially explicit global oil and gas infrastructure database for characterizing methane emission sources at high resolution." Earth System Science Data 15, no. 8 (August 24, 2023): 3761–90. http://dx.doi.org/10.5194/essd-15-3761-2023.
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Abstract. Reducing oil and gas methane emissions is crucially important for limiting the rate of human-induced climate warming. As the capacity of multi-scale measurements of global oil and gas methane emissions has advanced in recent years, including the emerging ecosystem of satellite and airborne remote sensing platforms, a clear need for an openly accessible and regularly updated global inventory of oil and gas infrastructure has emerged as an important tool for characterizing and tracking methane emission sources. In this study, we develop a spatially explicit database of global oil and gas infrastructure, focusing on the acquisition, curation, and integration of public-domain geospatial datasets reported by official government sources and by industry, academic research institutions, and other non-government entities. We focus on the major oil and gas facility types that are key sources of measured methane emissions, including production wells, offshore production platforms, natural gas compressor stations, processing facilities, liquefied natural gas facilities, crude oil refineries, and pipelines. The first version of this global geospatial database (Oil and Gas Infrastructure Mapping database, OGIM_v1) contains a total of ∼ 6 million features, including 2.6 million point locations of major oil and gas facility types and over 2.6×106 km of pipelines globally. For each facility record, we include key attributes – such as facility type, operational status, oil and gas production and capacity information, operator names, and installation dates – which enable detailed methane source assessment and attribution analytics. Using the OGIM database, we demonstrate facility-level source attribution for multiple airborne remote-sensing-detected methane point sources from the Permian Basin, which is the largest oil-producing basin in the United States. In addition to source attribution, we present other major applications of this oil and gas infrastructure database in relation to methane emission assessment, including the development of an improved bottom-up methane emission inventory at high resolution (1 km × 1 km). We also discuss the tracking of changes in basin-level oil and gas activity and the development of policy-relevant analytics and insights for targeted methane mitigation. This work and the OGIM database, which we anticipate updating on a regular cadence, help fulfill a crucial oil and gas geospatial data need, in support of the assessment, attribution, and mitigation of global oil and gas methane emissions at high resolution. OGIM_v1 is publicly available at https://doi.org/10.5281/zenodo.7466757 (Omara et al., 2022a).
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Scarpelli, Tia R., Daniel J. Jacob, Joannes D. Maasakkers, Melissa P. Sulprizio, Jian-Xiong Sheng, Kelly Rose, Lucy Romeo, John R. Worden, and Greet Janssens-Maenhout. "A global gridded (0.1° × 0.1°) inventory of methane emissions from oil, gas, and coal exploitation based on national reports to the United Nations Framework Convention on Climate Change." Earth System Science Data 12, no. 1 (March 11, 2020): 563–75. http://dx.doi.org/10.5194/essd-12-563-2020.
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Abstract. Individual countries report national emissions of methane, a potent greenhouse gas, in accordance with the United Nations Framework Convention on Climate Change (UNFCCC). We present a global inventory of methane emissions from oil, gas, and coal exploitation that spatially allocates the national emissions reported to the UNFCCC (Scarpelli et al., 2019). Our inventory is at 0.1∘×0.1∘ resolution and resolves the subsectors of oil and gas exploitation, from upstream to downstream, and the different emission processes (leakage, venting, flaring). Global emissions for 2016 are 41.5 Tg a−1 for oil, 24.4 Tg a−1 for gas, and 31.3 Tg a−1 for coal. An array of databases is used to spatially allocate national emissions to infrastructure, including wells, pipelines, oil refineries, gas processing plants, gas compressor stations, gas storage facilities, and coal mines. Gridded error estimates are provided in normal and lognormal forms based on emission factor uncertainties from the IPCC. Our inventory shows large differences with the EDGAR v4.3.2 global gridded inventory both at the national scale and in finer-scale spatial allocation. It shows good agreement with the gridded version of the United Kingdom's National Atmospheric Emissions Inventory (NAEI). There are significant errors on the 0.1∘×0.1∘ grid associated with the location and magnitude of large point sources, but these are smoothed out when averaging the inventory over a coarser grid. Use of our inventory as prior estimate in inverse analyses of atmospheric methane observations allows investigation of individual subsector contributions and can serve policy needs by evaluating the national emissions totals reported to the UNFCCC. Gridded data sets can be accessed at https://doi.org/10.7910/DVN/HH4EUM (Scarpelli et al., 2019).
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Toprakcioglu, Zenon, Tuuli A. Hakala, Aviad Levin, Christian F. W. Becker, Gonçalo J. L. Bernandes, and Tuomas P. J. Knowles. "Correction: Multi-scale microporous silica microcapsules from gas-in water-in oil emulsions." Soft Matter 16, no. 14 (2020): 3586. http://dx.doi.org/10.1039/d0sm90059a.
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Salawu, Babatunde A. "Technology Focus: Wellbore Tubulars (July 2023)." Journal of Petroleum Technology 75, no. 07 (July 1, 2023): 73–74. http://dx.doi.org/10.2118/0723-0073-jpt.
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Corrosion is a pervasive issue that affects oil and gas production. It poses a significant threat to the safety and integrity of oil and gas equipment, and it can lead to costly repairs and downtime. Mitigating corrosion is a crucial part of maintaining the productivity and safety of oil and gas operations. The first paper in the Wellbore Tubulars Technology Focus feature, IPTC 21818, explores the prevalence of corrosion in the oil and gas industry and the strategies used to mitigate its effect, including use of alternative materials and their qualification. The second paper in the feature, SPE 206340, deals with stuck-pipe incidents, a major cause of economic losses, safety hazards, and nonproductive time. With the use of artificial intelligence (AI) and machine learning (ML) techniques, however, these incidents can be prevented by analyzing drilling data. In recent research presented at the International Petroleum Technology Conference and other SPE conferences, various AI and ML models were developed to predict and prevent pipe-sticking symptoms. The authors of the paper used natural language processing applied to drilling memos to improve the accuracy and robustness of kick and lost-circulation detection. Finally, paper OTC 31160 discusses the use of microelectromechanical systems technology to embed sensors in tubulars that measure temperature and pressure throughout a well’s life. With low power consumption and an adapted transmission technology, this technology can be used to access previously inaccessible well areas in real time. Such technological strides in wellbore tubulars are revolutionizing the oil and gas industry by providing real-time data and making new areas of wells accessible. With the integration of intelligent pipe technology, nonmetallic casing strings, and powered wired drillpipe solutions, operators can better monitor their wells, adjust production parameters, and ensure the safety of their installations. These advancements are a significant step forward for the industry and are sure to have a positive effect on well integrity and safety for years to come. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202498 No Pipe Body Downgrades—Improved Corrosion Mitigation Coating System Provides Significant Operator Savings by Buck Johnson, Chevron, et al. SPE 205468 The Environmental Benefits of Repurposing Tubular Steel From North Sea Oil and Gas Fields by Rob William John Holdway, Giraffe Innovation, et al. IPTC 21455 Performance Improvement of Wells Augmented Stuck-Pipe Indicator by Model Evaluations by Meor M. Meor Hashim, Petronas, et al. IPTC 22660 First Successful Deployment of Nonmetallic Casing Strings: A Case History by Fauzia Waluyo, Saudi Aramco, et al.
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Collier, Graham. "Technology Focus: Offshore Facilities (September 2022)." Journal of Petroleum Technology 74, no. 09 (September 1, 2022): 75–76. http://dx.doi.org/10.2118/0922-0075-jpt.
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During the last great downturn in the oil and gas industry, I heard several glib comments along the lines of “the Stone Age didn’t end because we ran out of stones. … And now it’s the end for the oil industry.” At the time, I dismissed it as typical of our age, another short burst of one-line philosophy, just some attention-seeking doomsday prophecy that pops up far too frequently on our phones. So here we are in 2022, post COVID-19 (I hope), refreshed in thirst for oil, with commodity prices soaring, oil-producing company executives rubbing their hands with glee, and motorists complaining at the pump. All seems back to normal. But not so fast. The previous whisperings of the environmentalist movement have turned up in volume; change is now being shouted from street corners around the globe. While the oil and gas industry may be basking in the warmth of a new renaissance, there is a major shift toward carbon-free energy generation. Coastlines are being peppered with towering wind turbines, and the countryside is now farming more and more solar panels. Carbon capture and hydrogen generation are no longer science fiction fantasies and are now attracting interest, innovation, and investment. Does this all mean the glib comment about the “Stone Age” is about to come true? No. Not yet, anyway. At the turn end of the 19th century, coal was the major energy provider, but by the end of the 20th century, despite there being known huge reserves underground, coal mining had significantly declined in Europe and the Americas. Likewise with oil, at the start of the 21st century, oil and gas was the No. 1 energy provider, and the general consensus was that we would run out by mid-century. However, here we are, well into the third millennium, and oil and gas is still abundant, Saudi Arabia still sits on massive reserves as do some of its neighbors, and ExxonMobil appears to find a massive new oil field every time it drills a well off the Guyanese coast. Today, oil and gas are still important energy providers. They will remain with us throughout this century, but, like the coal industry, they will decline, not because we will run out, but because mankind will learn to harvest cleaner energy more favorable to the wellbeing of us all. In the meantime, I do hope that we are not so quick to rid ourselves of the impressive industrial engineering that is the legacy of a hundred years of oil and gas production. We find ourselves with a huge quantity of “idle iron” processing plants, refineries, offshore platforms, and a massive network of pipelines—idle, but not useless. Before the bulldozers and gas axes are released, there must be a drive for reuse of much of this infrastructure. It is comforting to see so much innovative thinking appearing in the Journal of Petroleum Technology advocating renewable energy and repurposing of aging oil and gas structures. It is worth noting that Stonehenge, built in Southern England more than 5,000 years ago, still functions as a remarkably accurate celestial calendar. I hope that you enjoy this month’s selection of technical papers. Recommended additional reading at OnePetro: www.onepetro.org. OTC 31494 - A Literature Review on Site Suitability and Structural Hydrodynamic Viability for Artificial‑Reef Purposes by Anas Khaled Alsheikh, UTP, et al. OTC 31986 - Alternatives to Conventional Offshore Fixed Wind Installation by Roy Robinson, Excipio Energy, et al. OTC 31655 - A Technical Limits Weight‑Control Tool for Integrity Management of Aging Offshore Structures by Sok Mooi Ng, Petronas, et al.
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Aswad, Zeiad A. R., Sameera M. Hamad-Allah, and Faaiz H. R. Alzubaidi. "STRATIFIED WATER-OIL-GAS FLOW THROUGH HORIZONTAL PIPES." Journal of Engineering 12, no. 04 (December 1, 2006): 1087–101. http://dx.doi.org/10.31026/j.eng.2006.04.14.
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Stratified three-phase flow through horizontal pipe has been studied experimentally. Thefluids used in the system are water, kerosene, and air. A closed loop flow system, which composedof 0.051 m inside diameter and 4 m length test pipe, is designed with facilities for measuring flowrate, pressure drop and thickness of each phase.The effects of gas, liquid flow rates and water liquid ratio (WLR) have been experimentallyobserved. It was found that liquid (water, and oil) thickness decreased when the gas flow rate isincreased with constant liquid flow rate, and increased when the liquid flow rate is increased atconstant gas flow rate. Pressure drop increased when the gas and/or liquid flow rate is increased.Three equations have been formulated, using the experimental data of the present work, topredict liquid, water thickness and system pressure drop in stratified three-phase flow in horizontalpipe. High correlation coefficients are obtained for these equations.The experimental results are compared with the results obtained from three-phase model ofTaital, Barnea, & Brill (1995). The comparison showed that the predicted data which obtained fromthree-phase flow model Taital et al. (1995) is in good agreement with experimental data.
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Cely, Alexandra, Ingvar Skaar, and Tao Yang. "Holistic Evaluation of Reservoir Oil Viscosity in Breidablikk Field – Including Mud Gas Logging Approach." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 64, no. 6 (December 1, 2023): 919–30. http://dx.doi.org/10.30632/pjv64n6-2023a8.
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Breidablikk is a green field on the Norwegian Continental Shelf that just started the preproduction drilling of 23 wells in two structures. We have two reservoir fluid samples from exploration wells in each structure with relatively high viscosity of 4 and 8 cP, respectively. Our dynamic reservoir simulations on the Breidablikk Field indicate that any change in the viscosity in each direction can lead to a 20 to 30% difference in oil recovery. Therefore, updating our reservoir models with the viscosity distribution in the field along with the drilling activities is important. Currently, our models assume homogeneous reservoir oil viscosities across each structure. In this study, our primary aim is to conduct a holistic evaluation of the reservoir oil viscosity, using multiple methods to determine the most effective approach for qualitatively mapping the oil viscosity across the field, distinguishing between the low- and high-viscosity regions. The technologies chosen for this assessment are standard mud gas data, advanced mud gas data, and analysis of oil extracts from cuttings, given they have previously demonstrated their capability to estimate fluid properties while drilling or within a limited time frame, as evidenced by the work of Cutler et al. (2022). The methods were compared using pressure/volume/temperature (PVT) measurements as a benchmark. As of today, this method is considered the most reliable to obtain reservoir fluid properties, and in consequence, these measurements serve as the reference viscosity values in the study. The results of our analysis in Breidablikk show that an approach based on advanced mud gas data provide an oil quality classification that distinguishes between high- and low-viscosity reservoir oils, using the ethane/n-pentane ratio as the best parameter correlated to reservoir oil viscosity in Breidablikk. The threshold for the two viscosity regions is identified from a reservoir fluid database from the Breidablikk-Grane area, and the oil viscosity region estimated from advanced mud gas data agrees well with the PVT measurements. The viscosity estimation using a standard mud gas approach based on methane to propane compositions indicates that this technology cannot correctly differentiate between low- and high-viscosity region wells in the Breidablikk Field. Hence, it is not recommended. Further findings from our analysis indicate that the utilization of oil-based mud, combined with a high drilling speed, significantly affects the quality of the cuttings in Breidablikk. Consequently, the application of traditional geochemical analysis methods on cutting extracts is challenging. Therefore, this method is not recommended for the qualitative identification of the viscosity region of a given well. Benchmarking all available technologies allows us to select a real-time, reliable, and cost-efficient method to qualitatively estimate reservoir oil viscosity in Breidablikk. The selected method is field-specific and not general for other heavy oil fields. In summary, providing an accurate reservoir oil viscosity mapping at an early stage in field development plays a crucial role in the further optimization of drilling targets and ultimately leads to improved oil recovery (Halvorsen et al., 2016; Maraj et al., 2021).
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Toprakcioglu, Zenon, Tuuli A. Hakala, Aviad Levin, Christian F. W. Becker, Gonçalo J. L. Bernardes, and Tuomas P. J. Knowles. "Correction: Correction: Multi-scale microporous silica microcapsules from gas-in water-in oil emulsions." Soft Matter 17, no. 1 (2021): 201. http://dx.doi.org/10.1039/d0sm90246b.
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Jain, Siddarth. "Technology Focus: Mature Fields and Well Revitalization (January 2024)." Journal of Petroleum Technology 76, no. 01 (January 1, 2024): 63–64. http://dx.doi.org/10.2118/0124-0063-jpt.
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In the relentless pursuit of a sustainable energy future, the often-overlooked potential of mature oil fields emerges as a beacon of hope. Once considered as being on the brink of abandonment, aging reservoirs are proving to be valuable assets as innovative hydrocarbon recovery techniques and re-envisioning of these fields for decarbonization opportunities are transforming them into reservoirs of opportunity. The sheer scale of mature oil fields globally is staggering. Advanced technologies and techniques, championed by internal initiatives that maximize the use of available data, are breathing new life into these reservoirs. While renewable energy sources are gaining traction, the world still relies heavily on hydrocarbons for its energy needs. One of the key advantages of reusing mature oil fields is the reduction in the need for new exploration and drilling. Exploring and developing new fields can be costly both financially and environmentally. By maximizing the recovery from existing fields, the industry can significantly decrease its ecological footprint and capitalize on the infrastructure already in place. Furthermore, the economic benefits of repurposing mature oil fields are substantial. The highlighted advancements focus on storage of various gases such as hydrogen, CO2, and natural gas, capitalizing on the knowledge gained from producing these fields for decades. Mature fields provide a bridge between the present and the future, offering a pragmatic solution to meet energy demands while mitigating environmental impact. Recommended additional reading at OnePetro: www.onepetro.org. SPE 214437 Fluid Modeling of Underground Hydrogen Storage in a Depleted Natural Gas Field by Markus Hays Nielsen, Whitson, et al. IPTC 22786 Particulate Wellbore Fluid-Strengthening Methodology—Design and Application in an Offshore Vietnam Severely Depleted Sand Reservoir by Dourado Motta Marcelo, SLB, et al. SPE 213405 Characterizing Movable and Nonmovable Zones in a Mature Carbonate Reservoir: A Novel Work Flow Using Resistivity Logs by Saud Al-Otaibi, Saudi Arabian Chevron, et al. SPE 214410 A Comparative Study of Hydrogen/Natural Gas Storage in a Depleted Gas Field in the Netherlands Using Analytical and Numerical Modeling by S. Hamidreza Yousefi, TNO, et al.
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BEN JEMAA, Mariem, Mejdi SNOUSSI, Hanen FALLEH, Raja SERAIRI BEJI, and Riadh KSOURI. "Phytochemical components and antioxidant and antimicrobial activities of essential oils from native Tunisian Thymus capitatus and Rosmarinus officinalis." Nutrition & Santé 10, no. 01 (June 30, 2021): 62–71. http://dx.doi.org/10.30952/ns.10.1.8.
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Introduction. Essential oils and their components are currently of great interest as a potential source of highly bioactive natural molecules. They are being studied for their possible use as safe alternative for food protection against oxidation and microbial spoilage. Objective. This study aimed on the phytochemical prospection of Thymus capitatus and Rosmainus officinalis essential oils and their oral toxicity evaluation. Material and methods. Chemical analysis of tested essential oils was carried out using gas chromatography combined to mass spectroscopic (GC-MS). Their safety limit was evaluated by acute toxicity. The antioxidant activity was estimated using in vitro methods. The antimicrobial activity was evaluated against twelve pathogenic germs. Results. Results showed that carvacrol and 1,8-cineol were the major compounds of Thymus capitatus and Rosmarinus officinalis essential oils. Acute toxicity results exhibited that both tested essential oils were inoffensive at 2000 mg/kg. Additionally, Thymus capitatus essential oil presented higher antioxidant activity than Rosmarinus officinalis: 2,2-diphényl-1-picrylhydrazyl (DPPH) assay results showed lower IC50 for Thymus capitatus essential oil than Rosmarinus officinalis. Concerning the antimicrobial results, Thymus capitatus essential oil presented greater efficacy than R. officinalis. Indeed, the minimal growth inhibition diameter generated by thyme essential oil exceeded 38 mm (except for Salmonella typhirium) and reached 60 mm (against C. tropicalis and C. albicans). However, the maximal growth inhibition diameter generated by R. officinalis essential oil was limited to 36 mm (against Shigella sonnei). Conclusion. Overall, Thymus capitatus and Rosmarinus officinalis essential oils have strong potential applicability for pharmaceutical industries.
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Kerimov, V. Yu, Yu V. Shcherbina, and A. A. Ivanov. "Formation conditions and evolution of oil and gas source strata of the Laptev sea shelf ore and gas province." Proceedings of higher educational establishments. Geology and Exploration, no. 3 (February 28, 2021): 46–59. http://dx.doi.org/10.32454/0016-7762-2020-63-3-46-59.
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Introduction. To date, no unified well-established concepts have been developed regarding the oil and gas geological zoning of the Laptev Sea shelf, as well as other seas of the Eastern Arctic. Different groups of researchers define this region either as an independently promising oil and gas region [7, 8], or as a potential oil and gas basin [1].Aim. To construct spatio-temporal digital models of sedimentary basins and hydrocarbon systems for the main horizons of oil and gas source rocks. A detailed analysis of information on oil and gas content, the gas chemical study of sediments, the characteristics of the component composition and thermal regime of the Laptev sea shelf water area raises the question on the conditions for the formation and evolution of oil and gas source strata within the studied promising oil and gas province. The conducted research made it possible to study the regional trends in oil and gas content, the features of the sedimentary cover formation and the development of hydrocarbon systems in the area under study.Materials and methods. The materials of production reports obtained for individual large objects in the water area were the source of initial information. The basin analysis was based on a model developed by Equinor specialists (Somme et al., 2018) [14—17], covering the time period from the Triassic to Paleogene inclusive and taking into account the plate-tectonic reconstructions. The resulting model included four main sedimentary complexes: pre-Aptian, Apt-Upper Cretaceous, Paleogene, and Neogene-Quaternary.Results. The calculation of numerical models was carried out in two versions with different types of kerogen from the oil and gas source strata corresponding to humic and sapropel organic matter. The results obtained indicated that the key factor controlling the development of hydrocarbon systems was the sinking rate of the basins and the thickness of formed overburden complexes, as well as the geothermal field of the Laptev Sea.Conclusion. The analysis of the results obtained allowed the most promising research objects to be identified. The main foci of hydrocarbon generation in the Paleogene and Neogene complexes and the areas of the most probable accumulation were determined. Significant hydrocarbon potential is expected in the Paleogene clinoforms of the Eastern Arctic.
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Xu, Lingfei, and Huazhou Li. "A Modified Multiple-Mixing-Cell Method with Sub-Cells for MMP Determinations." Energies 14, no. 23 (November 23, 2021): 7846. http://dx.doi.org/10.3390/en14237846.
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Minimum miscible pressure (MMP) is an essential design parameter of gas flooding for enhanced oil recovery (EOR) applications. Researchers have developed a number of methods for MMP computations, including the analytical methods, the slim-tube simulation method, and the multiple-mixing-cell (MMC) method. Among these methods, the MMC method is widely accepted for its simplicity, robustness, and moderate computational cost An important version of the MMC method is the Jaubert et al. method which has a much lower computational cost than the slim-tube simulation method. However, the original Jaubert et al. method suffers several drawbacks. One notable drawback is that it cannot be applied to the scenario where the oil-gas MMP is lower than the saturation pressure of the crude oil. In this work, we present a modified MMC method that is more versatile and robust than the original version. Our method can handle the scenario where the oil-gas MMP is lower than the saturation pressure of the crude oil. Besides, we propose a modified MMC model that can reduce the computational cost of MMP estimations. This modified model, together with a newly proposed pressure search algorithm, increases the MMP estimation accuracy of the modified method. We demonstrate the good performance of the modified MMC method by testing it in multiple case studies. A good agreement is obtained between the MMPs calculated by the modified method and the tie-line-based ones from the literature.
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Hassan, Omar F., and Dhefaf J. Sadiq. "New Correlation of Oil Compressibility at Pressures Below Bubble Point For Iraqi Crude Oil." Journal of Petroleum Research and Studies 1, no. 1 (May 5, 2021): 22–29. http://dx.doi.org/10.52716/jprs.v1i1.24.
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Oil compressibility represents a significant character in reservoir simulation, design of surface facilities and the analysis of well tests, specifically for systems below the bubble point pressure.
Oil compressibility is not directly measured in the laboratory. It is usually gained indirectly from experimental data recorded in PVT reports. The relative volume from the flash test is used to calculate oil compressibility at pressures above the bubble point pressure. At pressures below the bubble point, the reservoir behavior is simulated by the differential liberation test. The solution gas-oil ratio and the oil formation volume factor from the differential liberation test are employed in the estimation of oil compressibility at pressures below the bubble point pressure This paper purposes new correlation for calculating isothermal oil compressibility coefficient at and below bubble point pressure. The formulation of oil compressibility correlation is very difficult as it depends on many variables. This property is a function of many variables such as bubble point pressure, reservoir pressure, reservoir temperature, solution gas-oil ratio, oil formation volume factor, stock-tank oil gravity, specific gravity of gas and gas formation volume factor.
Standing’s (1), McCain et al. (2) and Al-Jarri's (3) correlations were submitted for testing their validity to evaluate their performance with Iraqi crude oils and to compare their results with the results of the new correlation.
The achievement of the new correlations has been done using two hundreds and nine data points from twenty PVT tests that were collected from Southern Iraqi fields. The evaluation of the previous correlations has achieved with graphical and statistical methods. These checking methods show a poor agreement between the observed and the calculated values.
The checking methods (graphical and statistical) explain that the new correlation that was achieved in this paper is suitable to calculate oil compressibility below bubble point pressure for Iraqi crude oils.
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Glaso, O. "Generalized Minimum Miscibility Pressure Correlation (includes associated papers 15845 and 16287 )." Society of Petroleum Engineers Journal 25, no. 06 (December 1, 1985): 927–34. http://dx.doi.org/10.2118/12893-pa.
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Abstract This paper presents a generalized correlation for predicting the minimum miscibility pressure (MMP) required for predicting the minimum miscibility pressure (MMP) required for multicontact miscible displacement of reservoir fluids by hydrocarbon, CO2, or N2 gas. The equations are derived from graphical correlations given by Benham et al. and give MMP as a function of reservoir temperature, C7+ molecular weight of the oil, mole percent methane in the injection gas, and the molecular weight of the intermediates (C2 through C6) in the gas. CO2 and N2 are represented in the current correlation by "equivalent" methane/propane- and methane/ethane-mixture injection gases, respectively. The study shows that for hydrocarbon systems, paraffinicity has an effect on MMP. In the equations, the C7+ paraffinicity has an effect on MMP. In the equations, the C7+ molecular weight of the oil is corrected to a K factor of 11.95, thereby accounting for varying paraffinicity. An additional temperature effect on N2 MMP is related to the API gravity of the oil. The N2 correlation, however, is not tested against measured MMP data other than those used to develop the equation and should be used with care. A correlation that accounts for the additional effect on CO2 MMP caused by the presence of intermediate components in the reservoir oil is presented. Predicted MMP's from the correlations developed are compared to experimental slim-tube displacement data from the literature and from our displacement tests on North Sea gas/oil systems. These displacement tests have been performed with a packed slim tube, where the effect of viscous fingering is reduced to a minimum. Introduction Multicontact miscibility is represented most easily with a ternary diagram, where the composition of the driving or displaced fluid is altered. This is obtained by vaporization of light hydrocarbon components into a driving gas or by condensation of hydrocarbon components from a driving gas into the reservoir oil. Miscibility between reservoir oils and hydrocarbon gases is achieved either by vaporization or by condensing-gas-drive mechanism, depending on the reservoir oil and injection-gas composition. With N2 and CO2, miscibility is obtained by vaporization, but with CO2, miscibility usually is achieved at lower pressure because CO2 extracts much higher-molecular-weight hydrocarbons from the reservoir oil than N2 gas. The prediction of miscibility conditions from ternary diagrams is based on experimentally determined or calculated gas and liquid compositions of a reservoir-oil/injection-gas mixture. The experimental gas and liquid equilibrium data are not easy to obtain and are often time-consuming to determine, especially near the plait point. The method for calculating gas and liquid data with point. The method for calculating gas and liquid data with equations of state to predict miscibility relies largely on gas and liquid compositions near the plait-point region. It is generally accepted that such data may not be sufficiently accurate. Flow experiments offer the most reliable method to determine the pressure required for miscibility with CO2, N 2, and hydrocarbon gas. The slim-tube method has been most widely used to determine miscibility. Different experimental procedures and interpretation criteria, however, have ted to different definitions of miscibility and have caused considerable confusion. The limitation of the slim-tube test and the problems associated with miscible displacement in porous media have been described by several authors. Phase behavior and mechanisms of miscible flooding with CO2, N2, and hydrocarbon gas have also been described by several authors. Correlations for predicting MMP have been proposed by a number of investigators and are important tools in the selection of potential reservoirs for gas miscible flooding. Therefore, the correlations must be as accurate as possible. Several CO2 MMP correlations have been published, but none of these can be used with enough published, but none of these can be used with enough confidence for final project design. They are useful, however, for screening and preliminary work. Correlations on CO2 miscible flooding have shown temperature to be the most important parameter but they disagree regarding the effect of oil type (e.g., C7+ properties of the oil). Compared with CO2 miscible flooding, very little has been published on high-pressure hydrocarbon gas miscible flooding. A recent publication gives a correlation for predicting MMP with lean hydrocarbon gases and nitrogen. In 1960, Benham et al. presented empirical curves that can estimate miscibility conditions for reservoir oils that are displaced by rich gas within a pressure range of 1,500 to 3,000 psia [10.34 to 20.68 MPa]. They assumed a limiting tie line (at the critical composition on a ternary diagram) parallel to the C1–C7+ axis and estimated mole percent methane in the injection gas from calculated percent methane in the injection gas from calculated critical points with pressure, temperature, molecular weights of C2 through C4 in the gas, and the C5+ molecular weight of the oil as variables. From Benham et al.'s data, the proposed equations have been derived for predicting MMP. SPEJ P. 927
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Baek, Hyun-Min, Dae-Yeong Kim, Won-Ju Lee, and Jun Kang. "Correction: Application of soot discharged from the combustion of marine gas oil as an anode material for lithium ion batteries." RSC Advances 10, no. 67 (2020): 41164. http://dx.doi.org/10.1039/d0ra90113j.
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Nengkoda, Ardian. "Technology Focus: Offshore Facilities (September 2021)." Journal of Petroleum Technology 73, no. 09 (September 1, 2021): 50. http://dx.doi.org/10.2118/0921-0050-jpt.
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For this feature, I have had the pleasure of reviewing 122 papers submitted to SPE in the field of offshore facilities over the past year. Brent crude oil price finally has reached $75/bbl at the time of writing. So far, this oil price is the highest since before the COVID-19 pandemic, which is a good sign that demand is picking up. Oil and gas offshore projects also seem to be picking up; most offshore greenfield projects are dictated by economics and the price of oil. As predicted by some analysts, global oil consumption will continue to increase as the world’s economy recovers from the pandemic. A new trend has arisen, however, where, in addition to traditional economic screening, oil and gas investors look to environment, social, and governance considerations to value the prospects of a project and minimize financial risk from environmental and social issues. The oil price being around $75/bbl has not necessarily led to more-attractive offshore exploration and production (E&P) projects, even though the typical offshore breakeven price is in the range of $40–55/bbl. We must acknowledge the energy transition, while also acknowledging that oil and natural gas will continue to be essential to meeting the world’s energy needs for many years. At least five European oil and gas E&P companies have announced net-zero 2050 ambitions so far. According to Rystad Energy, continuous major investments in E&P still are needed to meet growing global oil and gas demand. For the past 2 years, the global investment in E&P project spending is limited to $200 billion, including offshore, so a situation might arise with reserve replacement becoming challenging while demand accelerates rapidly. Because of well productivity, operability challenges, and uncertainty, however, opening the choke valve or pipeline tap is not as easy as the public thinks, especially on aging facilities. On another note, the technology landscape is moving to emerging areas such as net-zero; decarbonization; carbon capture, use, and storage; renewables; hydrogen; novel geothermal solutions; and a circular carbon economy. Historically, however, the Offshore Technology Conference began proactively discussing renewables technology—such as wave, tidal, ocean thermal, and solar—in 1980. The remaining question, then, is how to balance the lack of capital expenditure spending during the pandemic and, to some extent, what the role of offshore is in the energy transition. Maximizing offshore oil and gas recovery is not enough anymore. In the short term, engaging the low-carbon energy transition as early as possible and leading efforts in decarbonization will become a strategic move. Leveraging our expertise in offshore infrastructure, supply chains, sea transportation, storage, and oil and gas market development to support low-carbon energy deployment in the energy transition will become vital. We have plenty of technical knowledge and skill to offer for offshore wind projects, for instance. The Hywind wind farm offshore Scotland is one example of a project that is using the same spar technology as typical offshore oil and gas infrastructure. Innovation, optimization, effective use of capital and operational expenditures, more-affordable offshore technology, and excellent project management, no doubt, also will become a new normal offshore. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202911 - Harnessing Benefits of Integrated Asset Modeling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field by Yukito Nomura, ADNOC, et al. OTC 30970 - Optimizing Deepwater Rig Operations With Advanced Remotely Operated Vehicle Technology by Bernard McCoy Jr., TechnipFMC, et al. OTC 31089 - From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil by Paulino Bruno Santos, Petrobras, et al.
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Richardson, W. D., F. F. Schoeggl, S. D. Taylor, B. Maini, and H. W. Yarranton. "Diffusivity of Gas Into Bitumen: Part II—Data Set and Correlation." SPE Journal 24, no. 04 (May 9, 2019): 1667–80. http://dx.doi.org/10.2118/195575-pa.
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Summary The oil-production rate of in-situ heavy-oil-recovery processes involving the injection of gaseous hydrocarbons partly depends on the diffusivity of the gas in the bitumen. Data for gas diffusivities, particularly above ambient temperature, are relatively scarce because they are time consuming to measure. In this study, the diffusion and solubilities of gaseous methane, ethane, propane, and n-butane in a Western Canadian bitumen were measured from 40 to 90°C and pressures from 300 to 2300 kPa, using a pressure-decay method. The diffusivities were determined from a numerical model of the experiments that accounted for the swelling of the oil. In Part I of this study (Richardson et al. 2019), it was found that both constant and viscosity-dependent diffusivities could be used to model the mass of gas diffused and the gas-concentration profile in the bitumen; however, the constant diffusivity was different for each experiment and mainly depended on the oil viscosity. In this study, a correlation for the constant diffusivity to the oil viscosity is developed as a tool to quickly estimate the gas diffusivity. A correlation of diffusivity to the mixture viscosity is also developed for use in more-rigorous diffusion models. The maximum deviations in the mass diffused over time predicted with the constant and viscosity-dependent (mixture viscosity) correlations at each condition are on average 7.4 and 8.7%, respectively.
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Blanchard, Vincent, Didier Lasseux, Henri Jacques Bertin, Thierry Rene Pichery, Guy Andre Chauveteau, Rene Tabary, and Alain Zaitoun. "Gas/Water Flow in Porous Media in the Presence of Adsorbed Polymer: Experimental Study on Non-Darcy Effects." SPE Reservoir Evaluation & Engineering 10, no. 04 (August 1, 2007): 423–31. http://dx.doi.org/10.2118/99711-pa.
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Summary The objective of this paper is to report some experimental investigations on the effect of polymer adsorption on gas/water flow in non-Darcy regimes in homogeneous porous media, in contrast to previously available analyses focused mainly on the Darcy regime. Our investigation concentrates on gas flow either at low mean pressure, when Klinkenberg effects (or gas slippage) must be considered, or at high flow rates, when inertial effects are significant. The experimental study reported here consists of water and nitrogen injections into various silicon carbide model granular packs having different permeabilities. Experiments are carried out at different water saturations before and after polymer adsorption over flow regimes ranging from slip flow to inertial flow. In good agreement with previous works, in the Darcy regime, we observe an increase in irreducible water saturation and a strong reduction in the relative permeability to water, while the relative permeability to gas is slightly affected. At low mean pressure in the gas phase, the magnitude of the Klinkenberg effect is found to increase with water saturation in the absence of polymer, whereas for the same water saturation, the presence of an adsorbed polymer layer reduces this effect. In the inertial regime, a reduction of inertial effects is observed when gas is injected after polymer adsorption, taking into account water-saturation and permeability modifications. Experimental data are discussed according to hypotheses put forth to explain these effects. Consequences for practical use are also put under prospect. Introduction Water/oil or water/gas flows in porous media are strongly modified in the presence of an adsorbed polymer layer on the pore surface. Several studies, performed in the Darcy regime, showed a phenomenon of disproportionate permeability reduction (DPR). The relative permeability to water (krw) is reduced more than the relative permeability to gas (krg) or to oil (kro). Although this effect was observed over most of the water-soluble polymer/weak gel systems and rock materials, the origin of this effect is still controversial in the literature. Several physical processes have been put forth to explain the selective action of the polymer.Mennella et al. (1998) studied water/oil flows in the presence of an adsorbed polymer layer in random packs of monodisperse spheres. They concluded that the DPR was caused by a swelling/shrinking effect depending on the kind of fluid flowing throughout the packs. They also explained the DPR by pore-scale topological modification (pore-size reduction). Similar studies (Dawe and Zhang 1994; Sparlin and Hagen 1984) were carried out on different systems such as micromodels.Some authors (White et al. 1973; Schneider and Owens 1982; Nilsson et al. 1998) have interpreted the effect of polymer by assuming that a porous medium is composed of separate oil/water pore networks. With this representation, the DPR can be explained by the fact that water permeability is affected by the hydrosoluble polymer present in the pore network occupied by water, while oil permeability is not.Many studies attributed the DPR to a wall effect (Zaitoun and Kohler 1988, 2000; Barreau 1996; Zaitoun et al. 1998), which decreases the pore section accessible to water. The physical origin of this mechanism is adsorption—almost irreversible—on the solid surface. An adsorbed polymer layer on pore walls induces steric hindrance, lubrication effects, and wettability modification, all of which are in favor of a stronger reduction of water permeability than of oil permeability. The physical relevance of this mechanism was tested on numerical simulations at the pore scale (Barreau et al. 1997).Liang and Seright (2000), following Nilsson et al. (1998), proposed to complete the explanation of DPR by a "gel-droplet" model. In this scenario, gel droplets formed in pore bodies cause a higher pressure drop at the pore throat in the wetting phase than in the nonwetting one. These reported studies mainly have been dedicated to the polymer action on oil/water systems, and much less attention has been paid to gas/water flow. However, all available results in this last configuration lead to the same behavior, and the same type of physical explanation (wall effect) was proposed (Zaitoun and Kohler 1989; Zaitoun et al. 1991). If published results dealing with the effect of polymer on permeability reduction observed in the Darcy regime are quite numerous, very little work has been dedicated to the non-Darcy regimes. Elmkies et al. (2002) reported laboratory experimental data showing that adsorbed polymer on natural porous-media cores decreases the inertial effects during gas flow. In this paper, we focus our attention on the influence of adsorbed polymer on gas/water core flow in non-Darcy regimes. Gas injection was performed on unconsolidated cores having different permeabilities, at different water saturations, before and after polymer treatment, and at low mean pressure to investigate Klinkenberg effects, as well as at high flow rates, when inertial effects become important.
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Ladron de Guevara-Torres, Juan Ernesto, Fernando Rodriguez-de la Garza, and Agustin Galindo-Nava. "Gravity-Drainage and Oil-Reinfiltration Modeling in Naturally Fractured Reservoir Simulation." SPE Reservoir Evaluation & Engineering 12, no. 03 (May 31, 2009): 380–89. http://dx.doi.org/10.2118/108681-pa.
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Summary The gravity-drainage and oil-reinfiltration processes that occur in the gas-cap zone of naturally fractured reservoirs (NFRs) are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in the presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results. Gravity-drainage and oil-reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudofunctions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in the fractured reservoir simulation. The modified dual-porosity equations were implemented in SIMPUMA-FRAC (Galindo-Nava 1998; Galindo-Nava et al. 1998), and solutions were verified with good results against those obtained from the equivalent single porosity refined grid simulations. The same simulations--considering gravity drainage and oil reinfiltration processes--were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC. Introduction One of the most important aspects in the numerical simulation of fractured reservoirs is the description of the processes that occur during the rock-matrix/fracture fluid exchange and the connection with the fractured network. This description was initially done in a simplified manner and therefore incomplete (Gilman and Kazemi 1988; Saidi and Sakthikumar 1993). Experiments and theoretical and numerical studies (Saidi and Sakthikumar 1993; Horie et al. 1998; Tan and Firoozabadi 1990; Coats 1989) have allowed to understand that there are mechanisms and processes, such as oil reinfiltritation or oil imbibition and capillary continuity between matrix blocks, that were not taken into account with sufficient detail in the original dual-porosity formulations to model them properly and that modify significantly the oil-production forecast and the ultimate recovery in an NFR. The main idea of this paper is to study in further detail the oil reinfiltration process that occurs in the gas invaded zone (gas cap zone) in an NFR and to evaluate its modeling to implement it in a dual-porosity numerical simulator.