Iranian Journal of Oil and Gas Science and Technology

Abstract Residual oil saturation (Sor) estimation is a critical component of reservoir development and enhanced oil recovery (EOR) projects. Traditionally, Sor is estimated using the Archie method, in which accuracy strongly depends on petrophysical exponents, including the tortuosity factor (a), cementation factor (m), and saturation exponent (n). However, the conventional method assumes a homogeneous rock formation, rendering it ineffective and unreliable in shaly sand reservoirs. Additionally, field-based determination of petrophysical exponents and Sor is often difficult and time-consuming. This study addresses these limitations by developing a Python-based application that integrates a three-dimensional (3-D) regression technique with the Newton–Raphson algorithm. The application was tested using well logs from eight wells and statistically validated against core Sor data from the FAS Field, Offshore Niger Delta. Results indicated that the tortuosity factor (a) ranged from 0.28 (FAS-06) to 2.73 (FAS-04), the cementation factor (m) varied from 0.43 (FAS-06) to 4.11 (FAS-04), and the saturation exponent (n) ranged from 0.71 (FAS-04) to 8.59 (FAS-05). Correspondingly, Sor ranged from 0.11 (FAS-05) to 0.99 (FAS-06). The percentage deviation of the computed Sor relative to the core data ranged from 5% (FAS-01) to 27% (FAS-02) for the 3-D regression method and from 3% (FAS-03) to 52% (FAS-02) for the Newton–Raphson technique. The results indicate that the 3-D regression method is more efficient and reliable for computing petrophysical exponents and Sor in the study area.

Abstract The asphaltene and metal naphthenate components of crude oil samples from 10 wells within an oil reservoir were determined using different analytical techniques. The asphaltene content of the crude was determined by gravimetric analyses using American Standard for Testing and Material (ASTMD) 6560 to obtain its weight concentration. In contrast, the metal naphthenate components were determined by obtaining the metal ion concentration of the produced water and the naphthenic acid concentration of the crude using atomic absorption spectrometer (AAS) and potentiometric titration respectively. The results show that the asphaltene content of the crude samples ranges from 2.0000 to 8.000 wt %, while the naphthenic acid concentration indicated by the total acid number (TAN) ranges from 0.3000 to 1.4600 mg/KOH/g. All the crude samples possess asphaltene components and the propensity to form calcium and sodium naphthenate scale deposits with a Ca₂⁺ concentration between 32.5000 and 94.5000 mg/L and an Na⁺ concentration between 27.7 and 105.1 mg/L respectively. However, the formation of naphthenate scale deposits highly depends on the pH of the produced water of the crude, which makes well FT01 less likely to form naphthenate scales since it has a pH of less than 6; in other words, the produced water pH and availability of cations play an essential role in the formation of naphthenate scales. Calcium naphthenate scale formation is more favored at a brine pH higher than 6, while sodium scale formation is favored at a pH of approximately 8.5. An increase in produced water pH during crude oil production is usually caused by depressurization and CO₂ release. Both asphaltene and naphthenate deposits are directly proportional to the specific gravity of the crude and inversely proportional to the API gravity, implying that both components reduce the quality of the crude. Asphaltene and metal naphthenate solid deposits in the crude can cause many flow assurance difficulties, such as blocking expedition lines, pore plugging, wettability, crude oil parameter alteration, and reduction in oil recovery.

Abstract The organic geochemical characterization of crude oil samples from the oil fields of the Niger delta was carried out using gas chromatography–-mass spectrometry (GC–-MS) to genetically characterize the oil samples in terms of their biomarker composition. Geochemical characteristics such as depositional environments, kerogen type, and source of organic matter were analyzed using aliphatic biomarkers as a supporting tool. Five samples were randomly collected from Tebidaba, Clough Creek and Azuzuama fields in Bayelsa State, Nigeria. The saturated hydrocarbons were analyzed using GC–MS. The n-alkanes, isoprenoids, biomarkers hopanes, and steranes fingerprints were extracted from chromatogram for m/z 57, 191, 217 values respectively. The results revealed that the five studied samples were characterized by C₂₉ sterane predominance and the presence of oleanane, depicting organic matter with vascular land plant material inputs and a deltaic contribution. Ternary plots showed that the oils were deposited in an estuarine environment. The pristane (Pr) /nC₁₇ versus phytane (Ph)/nC₁₈ showed that TEB 08 and WELL 2 are in the anoxic environment inferring kerogen II and a mixture of types I and II respectively. TEB 12, CCST, and AZU ST has kerogen type III deposited in an oxic environment.

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 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.