Petroleum Engineering – Reservoir
Seyed Reza Shadizadeh; Amin Derakhshan
Abstract
Oil recovery from oil-wet carbonate rock is a significant challenge in the oil industry. The present study investigates the influence of the natural surfactant Hawthorn leaves extract (HLE) on oil recovery from carbonate rock. Two chemical surfactants, sodium dodecyl sulfate (SDS) and dodecyl tri methyl ...
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Oil recovery from oil-wet carbonate rock is a significant challenge in the oil industry. The present study investigates the influence of the natural surfactant Hawthorn leaves extract (HLE) on oil recovery from carbonate rock. Two chemical surfactants, sodium dodecyl sulfate (SDS) and dodecyl tri methyl ammonium bromide (DTAB), were used to validate and compare oil recovery with the new natural surfactant HLE. A wettability alteration test using the contact angle method, an interfacial test (IFT) using pendant drop, and core flooding were employed to investigate the behavior of the surfactants on oil recovery. The experimental results show that the critical micellar concentration (CMC) point of different concentrations of HLE, SDS, and DTAB solution occurs at 3.25, 3.00, and 4.06 wt %, respectively. In wettability alteration, the natural surfactant HLE is more effective than other chemical surfactants (SDS and DTAB) at the CMC point. As observed, the contact angle of the carbonate pellet and the HLE at the CMC point is 86°, and this angle for SDS and DTAB is 112° and 92°, respectively. The core flooding results show that the oil recovery factor improves from 37% with water flooding to 47.6% with SDS, 56.2% with DTAB, and 54.7% with HLE. The results prove that this new natural surfactant (HLE) can be used as a novel surfactant for the chemically enhanced oil recovery process in carbonate oil reservoirs. HLE has beneficial effects in oil recovery because of its environment friendly compared to SDS and DTAB.
Petroleum Engineering – Reservoir
Mohammad Ashrafi; Seyyed Alireza Tabatabaei-Nezhad; Elnaz Khodapanah
Abstract
Challenges of rock absolute permeability prediction of tiny samples are remarkable when laboratory apparatus is not applicable and there is no pore network modeling. The prediction using the characterization of micro-computed tomography images has been studied in this paper. Twenty series of 2D micro-computed ...
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Challenges of rock absolute permeability prediction of tiny samples are remarkable when laboratory apparatus is not applicable and there is no pore network modeling. The prediction using the characterization of micro-computed tomography images has been studied in this paper. Twenty series of 2D micro-computed tomography rock binary images have been collected, and each was considered a 3D binary image. Their geometric measures in 2D and 3D for measuring image properties have been considered using Minkowski functionals and available functions, developing a regression model; absolute permeabilities have also been evaluated. Some 2D and 3D geometric properties are considered. The area, the perimeter, and the 2D Euler number are 2D binary image properties. The volume, surface area, mean breadth, integral of the mean curvature, and the 3D Euler number are 3D binary image properties. The porosity and number of objects have also been considered parameters of a regression model. Twenty-four parameters were evaluated, and some were chosen to perform linear regression. An equation was proposed based on the extensive study to predict rock permeability. This equation has two sets of parameter coefficients: one set predicts high-permeability rocks (above two Darcy), and the other used for low- and medium-permeability rocks (less than two Darcy) can be employed for carbonated rock. The average absolute relative error for conducted cases is 0.06.
Petroleum Engineering – Reservoir
Temple N Chikwe; Mudiaga Onojake
Abstract
The geochemical investigation of trace metals in crude oils from some producing oil fields in the Niger Delta, Nigeria, was carried out to ascertain the petroleum source rocks and organic matter deposits. The concentrations of trace metals in crude oil samples obtained from eight producing fields from ...
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The geochemical investigation of trace metals in crude oils from some producing oil fields in the Niger Delta, Nigeria, was carried out to ascertain the petroleum source rocks and organic matter deposits. The concentrations of trace metals in crude oil samples obtained from eight producing fields from Niger Delta, Nigeria, were analyzed using a 700 model Perkin Elmer atomic absorption spectrophotometer. The results showed the following ranges for the trace metals: Cu (0.01–0.04 mg/kg), Fe (0.05–5.90 mg/kg), Ni (0.09–0.72 mg/kg); and V (0.008–1.05 mg/kg). Pb and Zn were lower than 0.01 mg/kg. Trace metal ratios such as V/Ni, V/Fe, and (V/V + Ni) were used to unravel the genetic correlation among the oils. All the crude samples except the sample from Nembe South-2 have a V/N ratio lower than 1.0, indicating that the organic materials produced the petroleum source rock. A cross plot of V/Ni revealed two genetic families for the crude oils, derived from a terrestrial and marine origin, which was confirmed by the ternary plot of V, Ni, and Fe, discriminating the crude oils from the producing fields into two distinct groups. The V/(Ni + V) of smaller than 0.5 showed that most crude oils were deposited in an oxic environment. A cross-plot of V/(Ni + V) and V/Fe showed a weak correlation, suggesting that it could not substitute for the V/Ni ratio in determining the origin and depositional environment of crude oil samples. Therefore, an in-depth knowledge of the concentration of trace metals, especially vanadium and nickel, within an environment during oil exploration is essential in developing new oil locations.
Petroleum Engineering – Reservoir
Seyed Reza Shadizadeh; Seyed Ramin Seyedi Abandankashi; Siyamak Moradi
Abstract
In recent years, the use of natural surfactants as surface active agents in chemical methods of oil recovery over chemical surfactants has been under consideration due to the absence of environmental problems. In this study, a new plant, Albizia julibressin (Albizia), was introduced as a natural surfactant. ...
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In recent years, the use of natural surfactants as surface active agents in chemical methods of oil recovery over chemical surfactants has been under consideration due to the absence of environmental problems. In this study, a new plant, Albizia julibressin (Albizia), was introduced as a natural surfactant. Our novelty resides in a unified approach that deals with the introduction of Albizia julibressin (Albizia) as a new natural surfactant, interpretation of the chemical EOR objectives, interface reactions, and the induced optimization to improve oil recovery. For this purpose, the plant was extracted using Soxhlet extraction method, aqueous base solutions and interfacial tension between natural surfactant aqueous solutions and kerosene as an oil phase were measured by pendant drop method. The critical micelle concentration structures formed by this material has been determined by interfacial tension tests and confirmed by electrical conductivity tests. The results show that Albizia extract at 3.5 wt% begins to form micelles structures, which is the critical concentration of Albizia plant micelles. At this concentration, the interfacial tension between the deionized water and the oil phase is reduced from 34 mN /m to 10 mN/m, which indicates a significant decrease in interfacial tension by this plant. Carbonate rock was employed to core flooding experiments in order to investigate the effect of Albizia extract (AE) on oil recovery. Also based on results, by using AE, wettability of oil-wet carbonate rocks, was altered from about 165.02◦ to 86.59◦. Finally, AE enhanced ultimate oil recovery about 11.6% of original oil in place in tertiary recovery for a carbonate rock.
Petroleum Engineering – Reservoir
Vahid Karamnia; Siavash Ashoori
Volume 10, Issue 1 , January 2021, , Pages 107-126
Abstract
< p>One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together ...
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< p>One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together to form a single phase. This pressure is typically abbreviated as MMP. Among the available methods for determining the minimum miscibility pressure, laboratory methods including slim tube test and ascending bubble apparatus test are more widely utilized. Although the mentioned tests have high measurement accuracy, they are very time consuming and expensive. Therefore, the determination of the minimum miscibility pressure is usually done using computational and simulation approaches that also have high accuracy. Conducting PVT tests and determining their MMP using slim tube method was previously performed. In this study, the minimum miscibility pressure of reservoirs was determined by applying three methods of simulation with PVTi software, simulation with Eclipse 300 software and using Empirical Correlations. By comparing the obtained results and the laboratory results, it was revealed that the simulation by Eclipse 300 is regarded as the fastest and most accurate approach.
Petroleum Engineering – Reservoir
Abiodun Ogbesejana; Oluwadayo Sonibare; Zhong Ningning; Oluwasesan Bello
Abstract
Crude oils and source rocks from the northern and offshore Niger Delta basin, Nigeria, have been characterized by gas chromatography-mass spectrometry in terms of their origin and thermal maturity based on the distribution of chrysene and its derivatives. The crude oils and source rocks were characterized ...
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Crude oils and source rocks from the northern and offshore Niger Delta basin, Nigeria, have been characterized by gas chromatography-mass spectrometry in terms of their origin and thermal maturity based on the distribution of chrysene and its derivatives. The crude oils and source rocks were characterized by the dominance of chrysene over benzo[a]anthracene. 3-methylchrysene predominated over other methylchrysene isomers in the oils, while 3-methylchrysenes and 1-methylchrysenes were in higher abundance in the rock samples. The abundance and distribution of chrysene and its derivatives allow source grouping of the oils into three families. However, this grouping disagrees with the results obtained from well-established aromatic source grouping parameters. The maturity-dependent parameters computed from chrysene distributions (MCHR and 2- methylchrysene/1-methylchrysene ratios) indicated that the oils have a similar maturity status, while the rock samples are within an immature to early oil window maturity status, which was further supported by other maturity parameters computed from the saturate and aromatic biomarkers and vitrinite reflectance data. The abundance and distribution of chrysene and its derivatives were found to be effective in determining the thermal maturity of crude oil and source rock extracts in the Niger Delta basin, but they may not be a potential source-dependent biomarker in the crude oils and rock extracts from the basin.
Petroleum Engineering – Reservoir
Behrouz Harimi; Mohsen Masihi; Mohammad Hosein Ghazanfari
Abstract
Gravity drainage is the main mechanism which controls the oil recovery from fractured reservoirs in both gas-cap drive and gas injection processes. The liquid bridge formed between two adjacent matrix blocks is responsible for capillary continuity phenomenon. The accurate determination of gas-liquid ...
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Gravity drainage is the main mechanism which controls the oil recovery from fractured reservoirs in both gas-cap drive and gas injection processes. The liquid bridge formed between two adjacent matrix blocks is responsible for capillary continuity phenomenon. The accurate determination of gas-liquid interface profile of liquid bridge is crucial to predict fracture capillary pressure precisely. The liquid bridge interface profile in the absence and in the presence of gravity is numerically derived, and the obtained results are compared with the measured experimental data. It is shown that in the presence of gravity, fracture capillary pressure varies across the fracture, whereas, by ignoring gravitational effects, a constant capillary pressure is obtained for the whole fracture. Critical fracture aperture which is the maximum aperture that could retain a liquid bridge was computed for a range of liquid bridge volumes and contact angles. Then, non-linear regression was conducted on the obtained dataset to find an empirical relation for the prediction of critical fracture aperture as a function of liquid bridge volume and contact angle. The computation of fracture capillary pressure at different liquid bridge volumes, fracture apertures, and contact angles demonstrates that if the liquid bridge volume is sufficiently small (say less than 0.5 microliters), capillary pressure in a horizontal fracture may reach values more than 0.1 psi, which is comparable to capillary pressure in the matrix blocks. The obtained results reveal that the variation of fracture capillary pressure versus bridge volume (which represents liquid saturation in fracture) obeys a trend similar to the case of matrix capillary pressure. Therefore, the capillary pressure of matrix can be applied directly to fractures considering proper modifications. The results of this study emphasize the importance of capillary continuity created by liquid bridges in the performance of gas-oil gravity drainage in fractured reservoirs.
Petroleum Engineering – Reservoir
Ali Kadkhodaie-Ilkhchi; Rahim Kadkhodaie-Ilkhchi
Abstract
Carbonate reservoirs rock typing plays a pivotal role in the construction of reservoir static models and volumetric calculations. The procedure for rock type determination starts with the determination of depositional and diagenetic rock types through petrographic studies of the thin sections prepared ...
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Carbonate reservoirs rock typing plays a pivotal role in the construction of reservoir static models and volumetric calculations. The procedure for rock type determination starts with the determination of depositional and diagenetic rock types through petrographic studies of the thin sections prepared from core plugs and cuttings. In the second step of rock typing study, electrofacies are determined based on the classification of well log responses using an appropriate clustering algorithm. The well logs used for electrofacies determination include porosity logs (NPHI, DT, and RHOB), lithodensity log (PEF), and gamma ray log. The third step deals with flow unit determination and pore size distribution analysis. To this end, flow zone indicator (FZI) is calculated from available core analysis data. Through the application of appropriate cutoffs to FZI values, reservoir rock types are classified for the studying interval. In the last step, representative capillary pressure and relative permeability curves are assigned to the reservoir rock types (RRT) based upon a detailed analysis of available laboratory data. Through the analysis of drill stem test (DST) and GDT (gas down to) and ODT (oil down to) data, necessary adjustments are made on the generated PC curves so that they are representative of reservoir conditions. Via the estimation of permeability by using a suitable method, RRT log is generated throughout the logged interval. Finally, by making a link between RRT’s and an appropriate set of seismic attributes, a cube of reservoir rock types is generated in time or depth domain. The current paper reviews different reservoir rock typing approaches from geology to seismic and dynamic and proposes an integrated rock typing workflow for worldwide carbonate reservoirs.
Petroleum Engineering – Reservoir
Ramin Moghadasi; Jamshid Moghadasi; Shahin Kord
Abstract
As a physiochemical property, asphaltenes are known to be one the most surface active compounds in crude oil. Due to such property, their behavior is most probably influenced by fluid-fluid interactions at the contact surface (interface). Potentially and naturally, in most cases, water is in contact ...
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As a physiochemical property, asphaltenes are known to be one the most surface active compounds in crude oil. Due to such property, their behavior is most probably influenced by fluid-fluid interactions at the contact surface (interface). Potentially and naturally, in most cases, water is in contact with crude oil and is co-produced with it as well. Considering that asphaltene molecules are polar compounds similar to water molecules, asphaltenes are interfacially affected by water while they are absorbed to the interface. Such effects could be investigated by interfacial tension (IFT) changes when de-ionized water is used and dead-crude oil does not contain other surface active impurities like metallic compounds. In this study, extensive IFT experiments were conducted between three different oil samples and distilled water in a wide range of pressure from 2000 to 0 psia. The reversibility of asphaltene absorbance to the interface was also investigated by reversing the pressure path from 0 to 2000 psia. The results show that oil/water IFT changes with pressure, but upward/downward oscillations were detected. Such an oscillating behavior of IFT trends was related to asphaltenes surface activity as the oil samples used did not contain other impurities. Oscillations were reduced as resin to asphaltene ratio was increased, suggesting the non-absorbable behavior of the asphaltenes stabilized by resins. A microscopic surface experiment on one of the samples showed that at a certain concentration and particle size, a rigid film of absorbed asphaltenes was created at the interface instantaneously. The high rigidity of such a film gives rise to a hypothesis, which states that water affects asphaltene surface behavior possibly through strong hydrogen bonding (H-bond). Reversing the pressure path revealed that asphaltene surface absorbance is partially irreversible. The experiments were conducted three times, and each data set was presented along with an average of three sets for each sample.
Petroleum Engineering – Reservoir
Azadeh Mamghaderi; Behzad Rostami; Seyed Hamed Tabatabaie
Abstract
In this study, direct laboratory measurements of unsteady-state imbibition test are used in a new approach to obtain relative permeability curves with no predetermined functionality assumptions. Four equations of continuity, Darcy’s law, cumulative oil production, and water fractional flow are ...
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In this study, direct laboratory measurements of unsteady-state imbibition test are used in a new approach to obtain relative permeability curves with no predetermined functionality assumptions. Four equations of continuity, Darcy’s law, cumulative oil production, and water fractional flow are employed in combination together under certain assumptions to present the new approach which interprets these data. We assumed that capillary pressure was previously measured and used as the input data in the method. The main difference between this work and previous unsteady-state methods is to replace the saturation profile, needed to obtain relative permeability curves, with a new saturation-dependent graph which can be measured from recovery data rather than being recorded directly during experiments. The method is demonstrated by employing recovery data from the literature, and it is then verified by a numerical simulator. The results show that the accuracy of the proposed method is comparable with accurate complex methods. Performing sensitivity analysis indicates that the proposed method can achieve more accurate results when applied to cases with a relatively high capillary number and/or low water-oil mobility ratio and when applied to media having uniformly sized pores.
Petroleum Engineering – Reservoir
Salih Awadh
Abstract
The oilfield water in the Upper Sandstone Member of the Zubair reservoir (Barriemian-Hauterivian) at Rumaila North Oil Field was investigated for the interpretation of salinity and geochemical evolution of brine compositions. The interaction of the oilfield water with reservoir rock resulted in a brine ...
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The oilfield water in the Upper Sandstone Member of the Zubair reservoir (Barriemian-Hauterivian) at Rumaila North Oil Field was investigated for the interpretation of salinity and geochemical evolution of brine compositions. The interaction of the oilfield water with reservoir rock resulted in a brine water derived from the marine water origin of partial mixing with meteoric water similar to the compositional ranges of formation water from Gulf of Mexico offshore/onshore Mesozoic reservoirs. The high TDS (207350- 230100; average 215625 mg/L) is consistent with the electrical conductivity (340362-372762; average 351024μs), and predominantly represented by Cl (123679 mg/L) as anions and (29200 and 14674 mg/L) for Na and Ca as cations respectively. The contribution of cation (epm%) are as Na (70.2), Ca (18.9), Mg (8.1) and K (1.7); and anion as Cl (99.7), SO4 (0.25), HCO3 (0.07) and CO3 (0.005). sodium (57550-60500mg/L) is greater than of seawater six times, calcium and magnesium three times greater, and chloride 6.5 times greater, but Sulfate is depleted to six times less due to a sulfur release from sulphates and link with different hydrocarbon species, precipices as native sulphur and link with hydrogen forming H2S. The Zubair oilfield water is characterised by acidic pH (pH=5.2- 5.77) enhanced petrophysical properties, high specific gravity (1.228) predicts a high fluid pressure (4866 psi), hydrocarbon saturation (0.43%), water saturation (0.57%) and porosity (12.7). The Mineral saturation model indicates that the Zubair oilfield water is an unsaturated water with respect to all suggested minerals at 5.45, but at simulated pH, brucite being an equilibrium at pH 9.12, but brucite and portlandite being supersaturated at pH 11.9. The mineral solubility responses to the changes in temperature, pressure, pH, Eh, and ionic strength, thereby formation damage is proportionally developed.
Petroleum Engineering – Reservoir
Shahriar Osfouri; Reza Azin; Hamid reza Amiri; Zahra Rezaei; Mahmoud Moshfeghian
Abstract
Gas condensate reservoirs are characterized by a distinctive retrograde behavior and potential for condensate drop out during production and sampling. Efficient modeling of gas condensate reservoir requires careful phase behavior studies of samples collected prior to and during the production life of ...
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Gas condensate reservoirs are characterized by a distinctive retrograde behavior and potential for condensate drop out during production and sampling. Efficient modeling of gas condensate reservoir requires careful phase behavior studies of samples collected prior to and during the production life of reservoir. In this work, an integrated characterization and tuning algorithm is proposed to analyze the pressure-volume-temperature (PVT) behavior of gas condensate samples. Each characterization and tuning scenario is described by a “path” which specifies the class of fluid, splitting and lumping (if any), the type of correlation, and grouping strategy (static or dynamic). Different characterization approaches were tested for the effective description of heavy end. Meanwhile, dynamic and static strategies were implemented to tune the equation of state (EOS) through non-linear regression. The optimum combination of characterization and tuning approach was explored for each sample by a rigorous analysis of the results. It was found out that the exponential distribution function gives the best performance for heavy end characterization in a dynamic tuning strategy. Also, analyses indicate that using higher single carbon number may not necessarily make EOS tuning more accurate. In addition, the optimum step is reached in either the third or fourth step for most cases in a dynamic tuning approach, and is sensitive neither to the characterization path nor to the selected end carbon number.
