Advances in Petroleum Engineering and Petroleum Geochemistry

Among all of the energy resources, oil is the most widely used primary energy source. Oil reservoirs need to be characterized accurately for effective field development purposes. Typically, available field data in the reservoir characterization stage may include seismic surveys, well logs, core analysis data and field production history. One of the challenges for reservoir engineers is to utilize various types of data collected in different scopes to characterize the reservoir and propose optimized development strategies. Numerical reservoir simulation is one of the most broadly implemented approaches to quantitatively evaluate a field development plan. However, establishing a decent reservoir simulation model requires rigorous conversions from the raw field data to structural maps and spatial petrophysical property distributions as input parameters. History matching needs to be carried out to tune the property distributions to match numerical model predictions to field histories. The conventional reservoir characterization and field development workflow could be time and labor intensive. This keynote lecture presents the development of artificial-neural-network based expert systems which effectively correlate seismic survey data, well log data and field production history. When compared against the conventional reservoir characterization and field development optimization protocols, the developed expert system can provide much more rapid predictions than conventional reservoir simulators.

Permeability is the ability of a saturated rock to let the fluid flow through its pores. Fluid flow circulation within the porous medium depends on the solid type and arrangement. It depends on diverse characteristics with a focus on mineralogical type and composition of the rock. Discrepancy on the petrophysical characteristics and essentially permeability and heterogeneity are associated to these listed factors. Accordingly, fluid flow is associated to solid–fluid and fluid–fluid contact by the involvement of properties such as wettability, contact angle and capillary pressure of fluid properties as well as the rock type, which together represent factors in charge, partially or totally, of the reservoir quality consideration. Thus, with the characterization of these property requirements and impact on fluid dynamics, a need of an intensive inquiry, aimed to enhance the possible physical phenomena and chemical contribution is vital. For the case study, our investigation is actually based on the determination of reservoir rock types using Discrete Rock Typing method. Application of the DRT method has been conducted towards the Ordovician in B-H Basin (Algeria). Outcomes have revealed the presence of six main reservoir rock types.

This paper intends to contribute to a better understanding of the Statfjord Formation in the North Sea, based on the study of some lithotypes of the Lourinhã Formation analog. A mineralogical and physical characterization was performed. A Fast RILEM water absorption test is herein proposed to carry out on sandstone drilled cuttings and cores that were cut into specimens, to assess permeability-related parameters. Results in a faster way on rocks with porosity values higher than 15% are given by this test in comparison to traditional laboratory methods. A correlation factor of 4–5 was obtained between permeability (mD) and water absorption coefficient (lb/ft2√h).

Recently, all over the world, hydrocarbon fuel reserves are deteriorating rapidly. The number of fields with hard-to-recover reserves is growing, the largest part of which are low-permeability reservoirs. In addition to problems with the development of this type of collectors, there is a difficulty in building hydrodynamic models of fields. All hydrodynamic simulators are based on the linear law of Darcy flow, so it is difficult to correctly adapt this model to the history of development, because this kind of objects has witnessed a nonlinear filtration. The construction of the hydrodynamic model is carried out in the simulator. Therefore, to adapt the model, it is necessary to select the parameters of the filtration medium, which are often far from the real studies of collectors. Tempest MORE of ROXAR, in which there is a possibility of modeling a nonlinear filtration for high-viscosity oil by “locking a gradient filter and a multiplier on the flow”. The former limits the well drainage area, and the latter reduces the fluid filtration rate multiple times. In the presented paper, the possibility of using this method to adapt the model for low-permeability reservoirs is described. Analytical methods for determining these critical pressure gradients are presented. Critical pressure gradients were analytically determined by using analytical methods following the example of the V. N. Vinogradova oil field with a low-permeability reservoir.

Dimensional analysis is applied on measured complex dielectric permittivity data of shaly sandstone rock samples, for the purpose of modeling the cation exchange capacity (CEC). These measured variables consist of rock porosity, specific surface area, and five other parameters of the Cole-Cole function, which describe the frequency dependence of the complex permittivity of rock samples in the range of 10–1300 MHz. The Cole-Cole function parameters are the characteristic relaxation time, the spread parameter, the real dc conductivity of water saturated rocks, the static dielectric permittivity, and the high-frequency dielectric permittivity of the water-saturated shaly-sandstone rocks. The dimensional analysis revealed the existence of two dimensionless groups, denoted as the cationic dispersion number (π1), and the conductivity number (π2). The former group π1 stands for the ratio of the cation exchange capacity to the electrical double layer dispersion. The latter group π2 represents the ratio of the low-frequency ionic conductivity to the high-frequency electronic polarization. The dimensionless groups have been validated using measured complex permittivity data of 92 shaly sandstone rocks. The dimensional analysis resulted in the derivation of a model for the CEC as a function of fast and non-invasive dielectric properties measurements. In return, accurate and fast estimates of CEC are useful in many petroleum engineering applications. They can be used to identify clay types, and to quantify the volume of hydrocarbon in shaly sands using well log resistivity data. The results of this study represent a major advantage for formation evaluation and wellbore stability analysis, as well as for designing stimulation jobs.

In this paper, we present an inexpensive approach based on a multilayer neural network, using two different algorithms to estimate permeability in petroleum reservoirs from well-logs data. In a supervised learning, the Back propagation (BP) and Hidden weight optimization (HWO) are tested in order to determine the best algorithm for better permeability predictions. The application to real data has been realized in the Algerian Sahara, exploiting data of several petrophysical parameters of Triassic reservoirs of two wells. The data of the first well are used to train the neural network machine as a pilot well, while the second well data were used for generalization to predict permeability. The obtained results are compared with permeability from core data.

This study uses a computerized formation evaluation system to investigate the permeability variation of high porous sandstone with reference to varying confining pressure, flowrate, time period of flow and temperature using brine as reservoir fluid. Permeability increases with increasing confining pressure, temperature and fluid flow period; however, it decreases with increasing fluid flowrates. The various permeabilities were determined at a confining pressure of 1060–3091 psi, a flow rate of 0.1–0.4 cc/min, an experiment duration of 10–40 min and a temperature of 26–42.3 °C. The results show that the time period of flow and fluid flowrates are two important parameters that are essential to obtaining an accurate permeability measurement but these cannot be operated at reservoir conditions during permeability determination, as these two parameters remain variables throughout the producing life of the reservoir.

The Salemba Field is the largest productive oil field in Barito Basin. This field is located in the north-eastern area of Barito Basin. An improvement was required for the Field development, either from the geology, reservoir, or production aspect. The aim of this study is to build a reliable static reservoir model that can match the production history when it was simulated in the simulation reservoir. In this study, the targeted reservoirs were in the A and B zones, which have the biggest oil production. The A and B zones represent the most productive units in the synrift filling sequence in Tanjung Formation, which mainly comprises medium to coarse grained sandstone, well to moderately sorted volcanic litharenitic and feldspathic litharenitic sandstone, and volcanic pebble-dominated conglomerates. These reservoir zones are separated by a continuous shale break indicating differences in the depositional event. Modeling the distribution of A and B zones was guided by a detailed well-to-well correlation, tracer data and production history as a data constraint. The integrated interpretation of these data was then used to derive net sand maps which were used as trends to guide geomodel facies and properties modeling. After building the conceptual reservoir element distribution model, geostatistical analysis for facies parameter population was conducted. Probability distributions for net sand maps and vertical proportion curves for facies distribution variability were also constructed. The reservoir rock type is defined by Flow Zone Index (FZI) equation combined with geology facies interpretation. The rock type will guide to generate permeability transform and J-function equation to distribute permeability (k) and water saturation (Sw) in the model. Our experiment shows that the model has a good agreement with the geological interpretation and production data. In addition, the base case model represents the best estimation. This model has been analyzed using a dynamic model and has shown a good simulation.

Low salinity water flooding (LSW) is considered as the major proposed EOR technique in which the salinity percentage of the injected water is adjusted in order to improve oil displacement efficiency; that is to say LSWI is considerably influenced by the oil recovery factor regarding altering the wettability condition. The amount of Total Field Oil production (FOPT), Total Field Gas production (FGPT), Field Pressure Ratio (FPR) and Field Gas-Oil Ratio (FGOR) were simulated for 7400 days while taking into consideration four parameters including NTG, porosity, rock compressibility and permeability in Z direction. As a result, rock compressibility and permeability in Z direction have less impact on the amount of FOPT, FGPT, FPR and FGOR. Moreover, NTG and Porosity have significantly affected each of the aforementioned factors.

Analyzing the sensitivity of high and low salinity, according to the moderately low recovery factor of high and low salinity among injection scenarios, illustrates the low sensitivity of this parameter in a fractured carbonated reservoir. By reviewing different scenarios, it could be demonstrated that if water injection was being applied to the reservoir from the preliminary times of production, the recovery factor rate will increase. Pure water injection has a high recovery factor than salty water injection. By the way, these two methods have a little difference in their recovery calculating methods. Moreover, in water injection methods, if the injection rate of water increases, the recovery factor will increase and give rise to a higher efficiency. Besides, this parameter is significantly dependent on well-head equipment properties, safety factors and economic issues (water production). Analyzing the figures and the volumes of low salinity water injection after the injection of pure water in different injection scenarios showed that all these scenarios have the highest rate of recovery and the maximum production efficiency.

The potential of divalent cation Mg2+ in formation water (FW) for low-salinity (LS) EOR effect was previously investigated [Al-Saedi et al. in Oil recovery analyses and formation water investigations for high salinity-low salinity water flooding in sandstone reservoirs. SPE, 190845, 2018 1], where the increase in divalent cations in FW lowered the effect of LS water. In this study, we studied the importance of the same divalent cation (Mg2+ only) in the injected water. Berea sandstone cores were successfully flooded with FW and LS water at 130 °C. While injecting both brines, samples of the effluent were analyzed for pH. Oil recovery experiments with a double Mg2+ concentration showed a lower LS water effect, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Mg2+ in the HS water was decreased by half.

Production of high-viscosity oil and design of field development systems for such oil is one of the most promising directions in the development of world oil industry. As a rule, oil of this class has pronounced structural–mechanical properties. Nonlinear relationship between the pressure gradient and the rate of oil flow is due to the interaction of high-molecular substances, in particular, asphaltenes and tars that form a plastic structure in it. We have used the analytical model of stationary influx of nonlinear viscoplastic oil to the well bottom in order to provide rationale for the intensifying impact on a reservoir. We have also analyzed the method of periodic heating of a productive reservoir by means of dual-wells. The suggested method of systemic treatment of reservoirs with dual wells can be useful for fields of high-viscosity oil.

The objective of this experimental study is to investigate the effect of CO2-oil contact time to oil swelling factor and viscosity. A sample from the central Sumatra basin was utilized in this study, which is categorized into paraffinic oil. The experiment condition follows the reservoir condition, which has a low fracture pressure. Thus, miscible injection scheme is impossible to apply. Therefore, the role of CO2 in reducing oil viscosity and oil swelling is emphasized. The experiments were performed under reservoir temperature by using PVT cell, syringe pump, and HPHT Rheometer. The result from the experiments clearly indicates that oil swelling and viscosity reduction mechanisms are quite effective during 24 h of CO2 injection. Optimum condition is obtained for the sample with 10 h of CO2-oil contact-time, where the swelling factor and viscosity reduction still show significant values.

Foam flooding is considered as one of the beneficial chemical enhanced oil recovery techniques to increase the value of gas viscosity and, thereby, the recovery of the produced oil would be improved dramatically, more than other methodologies. The objective of this comprehensive study is to determine a suitable injection model for Iran’s heterogeneous sandstone reservoir. Hydrolyzed polyacrylamide (HPAM) concentration in the foam solution has the most recovery factor in this case. Consequently, a concentration of 1200 ppm of HPAM in the foam solution produces a high volume of oil even after 10 years. Furthermore, by selecting three cores from the three wells in this field, it is clear that, owing to the increasing volume of foam in the injection fluid, the pressure dropped dramatically, leading to the production of a bigger volume of oil.

The efficacy of several nanoparticles [silica (Si), nanoclays, fly ash and iron oxide (IO)] in stabilizing CO2 foam is studied via flow experiments in a microfluidic device. The resulting foam is characterized using modified bulk foam tests. Size and uniformity of nanoparticle (NP) dispersions are quantified using dynamic light scattering. Results indicate that the size distribution and surface charge of the particles are influential parameters on the stability and formability of the foam, which in turn have a direct relationship with oil recovery performance. Si, nanoclays and fly ash NPs assisted by surfactant mixtures generate stable foams and result in high ultimate oil recoveries (over 90%). Even though IO-surfactant mixtures generate foams with relatively inferior stability characteristics and ultimate recovery, approximately three quarters of the IO NPs are recovered once exposed to a magnetic field. Unlike nanoclays and fly ash, the use of Si and IO NPs as foam stabilizers results in significant improvements in recovery at much smaller pore-volumes injected (~10 PVIs).

The impact of heterogeneity on the flow behavior of CO2 foam in the presence of crude oil is investigated in a complex, heterogeneous porous medium. A microfluidic device is fabricated featuring low and high permeability regions using a sequential photolithography technique. Two types of CO2 foams are used as the injectant: (i) foam stabilized with surfactants and (ii) foam stabilized with a blend of silica nanoparticles (Si NPs) and surfactants. High-resolution images of the medium during displacement experiments reveal a phase separation between the high versus low permeability regions; foam sweeps the high permeability regions, whereas the surfactant solution, along with few gas bubbles, appears to invade the low permeability region. The gains in recovery from the low-permeability region are attributed to the resistance to flow due to a relatively high apparent viscosity of foam in the high-permeability region and the resulting diversion of flow into the low-permeability region. The enhanced stability of foams stabilized with Si NPs appears to reduce the phase separation between the two regions, which contributes to an additional recovery gain from the low-permeability region.

The purpose of this research is to identify the synergetic effects of several parameters of an enhanced oil recovery mechanism by using sodium lignosulfonate (SLS) from bagasse. This is a laboratory research method conducted using SLS surfactant of bagasse injection process with that of light crude oil. The core injection was reinforced by the tested SLS surfactant characteristics such as IFT and contact angle. The core injection using SLS surfactant showed a high recovery factor at the two areas, at 5000 ppm salinity and at salinity of 80,000 ppm. At a higher salinity level, it produced a larger contact angle of 20°–50°. The interfacial tension value also increased from 2.73 to 4.11 mN/m. The value of oil recovery at these salinity variations ranged from 9.25 to 1.80%. The results of this research show that the mechanism of surfactant flooding depends on several parameters, like salinity, surfactant concentration, IFT and contact angle. The value of the formed contact angle also affects the performance of SLS surfactant in the oil purification process. Thus, it can be concluded that the parameters of the SLS surfactant in the injection process provide a synergetic effect on the oil recovery mechanism in terms of salinity, surfactant concentration, IFT, and contact angle.

The motivation for this work is an improved characterization of flow regimes for two immiscible phases in porous media. A microfluidic device featuring a water-wet porous medium that is based on a two-dimensional representation of a Berea sandstone is coupled with a high-resolution camera that allows the visualization of the entire domain, while being able to resolve features as small as 10 μm. Drainage flow experiments are conducted across a range of capillary numbers of 1E−4 to 9E−8. The viscosity ratios, defined as the viscosity of the resident fluid to that of the invading fluid, range from 1E−4 to 13.6E3. The findings are mapped on a two-dimensional parameter space (viscosity ratio and capillary number), and stability diagrams proposed in the literature are superimposed for comparison. Results suggest that the transition regime may occupy a much larger region of the flow regime diagram than is suggested in recent literature.

Microfluidic devices provide an experimental platform for direct observations of flow in complex channel networks. In this work, two-phase displacement experiments are conducted using a microfluidic device, featuring a complex network that is representative of a sample of Berea sandstone. The porous medium is placed in the field of view of a high-resolution camera with a monochromatic sensor—data captured in the form of images cover the entire medium while maintaining the resolution needed to discern features as small as 10 μm. This paper presents the series of steps required to convert these images into saturation maps that may be used for comparisons with predictions of numerical simulation models. The main steps include: exclusion of the grains; perspective transformation to correct minor misalignments of the device in each experiment; calculation of the Representative Elementary Volume; local thresholding strategy to account for non-uniform illumination across the medium; and finally, calculation of saturation maps.

Two-dimensional, high-resolution, numerical solutions for the classical formulation and two widely accepted nonequilibrium models of multiphase flow through porous media are generated and compared. Flow equations for simultaneous flow of two immiscible phases through porous media are written in a vorticity stream-function form. In the resulting system of equations, the vorticity stream-function equation is solved using a spectral method and the transport equation is discretized in space using a central-upwind scheme. A semi-implicit time-stepper is used to solve the coupled system of equations. The solutions reveal that inclusion of dynamic capillary pressure sharpens the front and lengthens the viscous fingers. The inclusion of nonequilibrium effects in constitutive relations introduces diffusion and smears the otherwise highly resolved viscous fingers in the saturation front.

The gravitational variations are a recurring registered event from the possibly experimental station of Rovigo (Italy). The intervals of variations have a duration from 9′ to 21′ 23′ and these continue to happen for temporary intervals from some hours to some weeks. The important variations of local microgravity, roughly 27 milligal, is registered as an equivalent of a strong earthquake. The gravitational variations should rarely happen in the absence of seismicity. The authors interpret the complex phenomena of gravitational local variations as the results of undulatory interferences generated from the Oil reservoir in areas of definite hydrocarbon occurrence. The study, which started in 1999, should add new geophysical concept suggesting a new non-invasive research preliminary method in order to locate oilfield hydrocarbon deposits.

Microbial prospecting for oil and gas (MPOG) method for bacterial detection is widely applied in surface geochemical exploration for oil and gas deposits. The modified MPOG method was applied in the Guebiba-Sfax basin of the Tunisian Republic which showed signs of hydrocarbon generation and proved oil production. This technique is based on seepage of light hydrocarbon gases such as C1–C5 from the oil and gas reservoir to the shallow surface, providing a good environment for the development of highly specialized microbial populations. These bacteria utilize hydrocarbon gases as the only food source and are found enriched in the near-surface soils above the hydrocarbon bearing structures. The present research work employs methodologies of high significance with the potential to reduce risk in petroleum exploration. For this purpose, we collected a total of 51 soil samples from the Eastern central region of Tunisia and we used the propane oxidizing bacteria as an indicator in the present study.

The heat flow (Q) of a sedimentary level depends on two basic parameters which are: temperature and thermal conductivity. However, so far in Tunisia, heat flow estimations are usually carried out based on temperature corrections only. This study tries to emphasize the effect of thermal conductivity variations on the thermal history of the Djeffara Basin, through the evaluation of its conductivity change following a high-resolution appraisal (5 m margin). The thermal flow, determined by the Fourier and the Bullard Plot methods, was estimated using the temperature corrections equation combined with the conductivity corrections based on porosity data. Consequently, we believe that a better reconstruction of the regional distribution of the thermal flow of the region in relation to its geodynamic evolution was achieved. The most realistic scenario compared to the geologic model shows an average heat flow equal to 82 mW/m2, which is higher than the global average of about 64 mW/m2.

Based on the oil-gas exploration data of Baodao Northern Slope in Qiongdongnan basin, the abundance of the adsorbed hydrocarbon and the abundance of brine inclusions with hydrocarbon were evaluated by quantitative grain fluorescence experiment. Combined with stages of fault activities, fault sealing capacity and the oil-gas charging time, the fault control on hydrocarbon migration and accumulation characteristics of Baodao Northern Slope was analyzed. The results show that the oil and gas reservoirs of the N1m–N1s Formation (21–10 Ma) of Baodao Northern Slope were formed very late, so, the particle surface adsorbed hydrocarbon abundance of shallow N1m–N1s Formation is prevalent and high with a low abundance of intragranular hydrocarbon. However, the oil and gas reservoirs of E3l Formation (30–21 Ma), close to the Baodao Sag, were formed earlier but most of them were destroyed later, and therefore the hydrocarbon abundance characteristics are different. Because of the limited migration ability, the oil and gas generated from the Baodao Sag mainly contributed to the south of Baodao Northern Slope, and they have little contribution to the northern part. The hydrocarbon generated from Oligocene source rock migrated vertically through the widely developed faults rather than along the lateral delta front sands.

Nowadays, the adverse effect of drilling operations on the ecological system pushed the oil industry specialists to achieve optimum drilling performances. Volume and toxicity of discharged materials evaluate surface discharge severity. The ubiquitous utilization of formate fluids has revolutionized the way petroleum industries have conquered the lower drilling inefficiencies. As an objective of this extensive study, the profound impact of different pollutants on the potassium/sodium formate fluids was investigated by experimental tests. The particular sample for mud pollution test was formate fluid with starch biopolymers. To do this, five samples of formate fluids were made, and each one of them was polluted by several contaminants such as cement, lime, acid, alkali and stucco. Consequently, the rheological properties and the pH changes, as well as their effects on the formate fluids were evaluated.

Most managers know that process-risk mapping is essential in enterprise design so as to obtain better understanding and management practices. Organizations need an effective and robust process of management that is less sensitive to changes in the business environment. The main purpose of this paper is the integration of process mapping and risk mapping, with a case study applied in an Algerian company in the oil and gas industry.

Produced water is the largest volume of wastewater generated during oil and gas production. It comprises of organic and inorganic compounds. The amount of produced water from various oil fields of Upper Assam Basin are increasing with the ageing maturity of the oil field. Produced water adversely affect the environment as it contains different toxic compounds such as petroleum contaminants and impurities include oil, naturally occurring radioactive minerals, oil & grease, hydrocarbons, production chemicals and various materials. This paper determines the quantitative and qualitative characterization of physical and chemical properties of produced water generated from different depths and horizons of Upper Assam oil fields. As produced water is re-injected into the reservoir for pressure maintenance and is discharged into the environment, so its characterization is highly significant for environment and reservoir management. The characterized physical and chemical properties of produced water have higher values which will adversely affect the environment. The characterized results are validated in Lenntech software to determine the corrosion and scaling forming tendency of produced water on the basis of Ryznar stability index and Langelier saturation index. The produced water samples are found to be highly corrosive and it has tendency to form scale. The samples are also highly corrosive.

Formation water constitutes the biggest oil by-product of oil exploration and production industries, which disturbs the ecological balance. In view of the above, this study is an attempt to examine the physical and chemical parameters of formation water and to determine the scaling potential of untreated and treated formation water by Ryznar stability index and Langelier saturation index calculators. Ten samples of crude oil containing more than 70% formation water are collected from the wellheads of ten production wells of the Upper Assam Basin. Analyses of the parameters of the separated formation water from crude oil are found to be outside the permissible range set by the Central Pollution Control Board of India which gives us a clear view that the untreated water cannot be discharged to the environment until proper treatment is done. The formation water samples are treated in a parallel flow hollow fiber membrane module by micro-filtration, ultra-filtration and nano-filtration membranes in sequence. The parameters of the treated samples by nano-filtration are found to be within the range set by the Central Pollution Control Board of India, therefore, it can be disposed of without affecting the environment. The scaling potentials are evaluated by Ryznar stability index and Langelier saturation index calculators of the untreated and treated formation water. The untreated water sample forms heavy scales than the treated ones.

This project focuses on the changes in the characteristics and properties of cement slurry while adding different environmentally friendly additives. To properly implement the cementing job, cement should have the desired properties and characteristics. It should have very low permeability, high strength, sufficient thickening time and pump-ability to reach the target depth and the desired density, depending on the conditions of the well. To control the cement properties and obtain the desired characteristics, additives are usually used and mixed with plain cement. In this project, new and novel additives, including cactus powder, hay bran, hay bran ash, rice husk, and rice husk ash were used and mixed separately with the plain cement. The plain and blended cement samples were exposed to various API cement tests, including the compressive strength test, gas-permeability test, fineness test, and density test. This paper focuses mainly on the results of the compressive strength test conducted on the plain cement and rice husk ash, hay bran ash blended with cement. Results showed that the rice husk ash blended cement at a 10% replacement level exhibited the highest value of compressive strength, whereas the other non-ash additives adversely affected the strength of the cement.

Upper Jurassic Naokelekan organic-rich strata are ubiquitous across the Kurdistan Region of Iraq. Laterally, continuous layers, of substantial thickness, outcrop in the highly folded and imbricated zones and in subsurface sections in the Low Folded Zone. In this study, 15 samples from 5 outcrops, viz., Barzinja, Sargelu, Barsarin, Karak, and Bnavya, were examined, which represent the entire lithological alternations of limestones and shales encountered in the Whole Naokelekan Formation. This study assesses the type, the thermal maturity and the petroleum generation potential of the organic matter contained in the upper Jurassic Naokelekan formation throughout the area. The qualitative petrographical evaluation of the studied samples revealed that the main organic constituents are solid hydrocarbons, in the form of microgranular migrabitumens, with minor amounts of pyrobitumens. Equivalent vitrinite reflectance estimations (0.59–1.12% Ro) indicate that the upper Jurassic sequence in the western part of the area is at a mature stage, while the same sequence in the eastern part is at late mature stage.

Microscopic observations were conducted on cutting samples of well A, in the northern Song Hong basin. This is to estimate the hydrocarbon source potential by classifying different types of kerogen based on composition. In the section of 1646–2350 m, the organic matters comprise vitrinite particles of more than 50% mixed with secondary assemblages of algae, amorphous, resin and liptodetrinite. This is classified as mainly type III with minor type II/I kerogens, indicating that it is mainly associated to gas-prone and minor oil-prone source rock. In the section of 2445–2850 m, the organic matters contain more amorphous matters than the former section (35–50%), while vitrinite particles range between 35 and 40%. This represents major type I and III kerogen mixed with minor type II kerogen, indicative of both oil- and gas-prone source rocks.

Potential organic-rich rocks have been sampled onshore Cyprus and offshore, along the Eratosthenes Sea Mount. Offshore, potential source rock intervals are mainly present in the Upper Eocene and in the Lower Upper Cretaceous. In the onshore area, good source rock properties are reached in Upper Miocene intervals. These samples contain marine oil-prone type II kerogen. TS/TOC as well as several biomarker ratios indicate anoxic depositional conditions for the onshore samples and dysoxic conditions for the offshore ones. Tmax values around 420 °C and VRr values lower or equal 0.5 indicate an immature state of the organic matter. However, in terms of biogenic gas, these immature rocks might contribute to natural gas generation in the area. Furthermore, the Upper Miocene as well as the Upper Eocene sections might continue in the deeper offshore parts, where burial depths are sufficient for thermal maturation. The presence of thermogenic hydrocarbon generation is indicated by the presence of solid bitumen staining in Lower Eocene offshore intervals.

This paper investigates the sedimentary characteristics, geochemical indicators of source rock, and the hydrocarbon potential in detail within the Paleogene and Upper Cretaceous in the northern Kaikang trough, Muglad Basin. Analysis shows that the thickness of good source rocks in Paleogene ranges from 50 to 200 m, and the TOC value can reach 0.5–1.3%, but it is immature and has no hydrocarbon generation potential. Nevertheless, the Upper Cretaceous source rocks had mostly entered the maturity threshold, with a TOC value of only 0.5–0.8%, and a thickness of only 10 m, so the hydrocarbon generation is limited. The main effective source rock is the AG Group in the Lower Cretaceous, which is distributed throughout the area. The evolutionary history shows that most of the structures in the central troughs lack hydrocarbon potential, because they were formed since the Paleogene, which is later than the main accumulation period of the AG source rock. Petroleum discovery was made in the fault terrace zones on both sides of the Kaikang Trough, but the distribution of oil layers is very complicated. Hydrocarbon accumulation is controlled by formation dips, fault activity intensity and fault lateral docking characteristics. The weaker active fault block in late time and the more effective trap are the key to hydrocarbon enrichment at the fault terrace-zones.

The geological landscape in Northern Tunisia is dominated by its diapiric structures that started its ascending movements since the late Triassic to Early Cretaceous. This movement is driven by a mechanism known as Halokinesis. The main objective of this study is to establish the relationship between the salt structure setting and the maturity of the surrounding source rocks especially the Cenomanian-Turonian Bahloul Fr. In order to assess the maturity history of the source rock, we analyzed several black shale samples from around Jebal Ech cheid by means of Rock Eval pyrolysis and GC/MS. Our results demonstrate a total organic Carbon (TOC) percentage of 1–9% and a Tmax maturity between 424 and 445 °C. In addition, the distributions of the source rock biomarkers saturated as well as aromatic, change in a specific trend of increasing maturity from the SW to the NE of the structure. This change is also proven when using GC/MS technique to analyze the saturated and aromatic biomarkers such as Ts/Ts+Tm ratios, 22S/22S+22r values for C31 homohopanes, and 20S/(20S+20R) ratios for C29. The results from Rock Eval and GC/MS analyses demonstrate that the salt structure played a role in modifying the geothermal gradient of the basin and in the maturity of the source rock in Bahloul Fr., the individualization of subsidence and deep-seated faults are the main reasons behind the maturity contrast between the studied zones. The organic matter has reached different stages of thermal maturity with a general increasing maturity trend (SW to NE).

Permian rock samples from two wells (W-1 and W-2) drilled in the Jeffara basin (Southern Tunisia) were analyzed using the Rock Eval pyrolysis (RE) and Gas chromatography coupled to Mass Spectrometry (GC/MS). Oil indices from the same series were also examined. The two objectives pursued through this study were: (1) First, to geochemically characterize the Permian series in order to determine their source rock potential; (2) Second, to identify the origin of hydrocarbons occurring in the Permian layers through oil-oil correlations and oil correlations to source rocks candidates (Permian, Azzel, Fegaguira, and Zoumit). The attained results show that the lower part of the Permian series is rich in organic matter and may constitute a good source rock of an “Oil and Gas-prone” quality. The oil indices found in the top part of the Permian series were generated simultaneously by the Permian source rock and the Paleozoic source rock (Azzel and Fegaguira). The 1D basin modeling results indicate that, overall, the hydrocarbon generation started since the Permian (240 Ma) while oil expulsion took place during the Upper Triassic (230 Ma).

This study evaluates the geopetroleum assessment of the Ordovician series (El Atchane and El Hamra reservoirs) and the Triassic series (TAGI), in the Southern Chotts region, based on well logging data. The burial and thermal maturity history of the potential source rock Fegaguira Formation (Silurian in age) of the area, was accomplished using the BasinMod software. The generation and expulsion times of hydrocarbons in the region, as well as their quantities were also estimated. The Ordovician reservoirs (El Atchane and El Hamra) generally show the same petrophysical characteristics (the porosity of the two reservoirs varies between 5 and 12%) with a decrease in thickness from west to east until the total disappearance of the El Hamra Formation. This variation was related, on the one hand, to the bevelling of the Ordovician on the Telemzane arch and, on the other hand, to the erosive effects of the orogenic phases during Paleozoic (Taconic, Caledonian and Hercynian phases). The maturity history modeling of four wells in the south of the Chotts region shows that the Fegaguira source rock is mature and began generating hydrocarbons during the Early Cretaceous and expelled its hydrocarbons from the Paleogene in the wells 5 and 7 and from Cretaceous in the well 13 (at a SATEX of 10%). The Fegaguira source rock has not expelled in the well 19. The quantity of oil expelled by the Fegaguira source rock reached 36.3 bbl/acre ft rock and 33 bbl/acre ft rock in the wells 5 and 7 during Paleogene and 53.5 bbl/acre ft rock in the well 13.

Five stratigraphic intervals in the Mesozoic–Cenozoic complex, which are distinguished as the source rocks within the western flank of SCB, are identified on the basis of geochemical study and petroleum system modeling: Eocene, Oligocene–Lower Miocene, Middle Miocene, Upper Miocene, and Lower Pliocene. Their hydrocarbon generation potential and maturity have been assessed. Retrospective analysis of the distribution of the hydrocarbon generation pots, at the different periods of geological time, shows that spatial distribution of HC generation pots is mosaic and corresponds to tectonic structure, lithological heterogeneity and generation potential of separate stratigraphic complexes, heterogeneity of heat and geobaric fields.

This investigation examines the samples of Imo Formation from Nzam-1 well, Anambra basin, to identify the source of organic matter, the depositional environment, thermal maturity and tectonic setting. The sediments consist of grey to dark grey, less gritty fissile shales, with no distinct grainy appearance or layered structure, and white to grey sandy shales with intercalations of fine grained sandstones. Biomarker results indicate short to middle chain n-alkanes, low to medium CPI values and narrow range of Pristane/Phytane ratio. Major oxides in the samples follow the trend: SiO2 > TiO2 > Fe2O3. Trace elements such as Sr, Ba, V, Ni, Co and Cr were identified. The biomarker results suggest thermally immature to early mature sediments deposited in anoxic to sub-oxic environment. The biomarkers of terpanes and steranes indicate derivation from a mixed marine algal source with minor contributions from terrigenous inputs. Trace element ratios also indicated oxic to dysoxic bottom water conditions, reflecting mixed terrigenous and marine conditions. Major oxide ratios indicated that samples were sourced from a passive continental margin under humid paleoclimatic conditions. Geochemical parameters (Cr/Ni, and Th/Cr ratios etc.) suggested a felsic dominated basement source.

Nine heavy oils were analyzed to investigate the biodegradation of biomarkers. According to the characteristics of the presence of a fully developed series of 25-norhopanes and to the conspicuous depletion of hopanes, regular steranes and even tricyclic terpanes, the level of biodegradation of the samples were determined as ranging from PM 6 to PM 9. Among the samples, hopanes and regular steranes were biodegraded severely and the depletion of hopanes and of regular steranes increased with the increase of the biodegradation level. When the level of biodegradation reaches PM 8, the biodegradation of tricyclic terpanes begins. With the increase of biodegradation, the C21–22 steranes and diasteranes remain unaffected under the biodegradation level of PM 8, indicating that they can be used as conserved “internal standards” to evaluate the biodegradation of hopanes, regular steranes and tricyclic terpanes. However, the C21–22 steranes and diasteranes are degraded when the biodegradation level is over PM 9. Among the C19–26 tricyclic terpanes family, C23 and C21 tricyclic terpanes are the most readily degraded members, followed by C20 tricyclic terpane, while the C19, C22 and C24–26 tricyclic terpanes seem more resistant to biodegradation.

This study is an attempt to understand the role played by different formation water and crude oil samples in chemical enhanced oil recovery. The study pertains to the characterization of these samples in Agilent Gas Chromatography-Mass Spectrometry in order to determine the organics. The organics were further analysed in the library database of the National Institute Standards and Technology, to identify saturated and unsaturated compounds, organic alcohols and carboxylic functional groups in hydrocarbons. The presence of naphthenes and aromatics was also detected. Crude oil samples showed the presence of saturated and unsaturated hydrocarbons, with a predominance of –OH and –COOH functional groups in the hydrocarbons. While the formation water samples showed the presence of unsaturated hydrocarbons and hydrocarbons containing the –OH functional group with the predominance of saturated hydrocarbons. The presence of –COOH in the reservoir fluids, during the alkaline enhanced oil recovery, leads to the formation of in situ surfactant. The presence of –OH in the reservoir fluids leads to the reduction of wettability between the porous media and the oleic phase. The total acid number of the crude oil increases due to the presence of naphthenic acid, which is formed by the reaction of naphthenes with the –COOH group. The predominance of –OH and –COOH functional groups in crude oil samples enhances the release of more oil from the negatively charged clay surfaces of the Upper Assam Basin.

The geochemical assessment of a shale gas reservoir in the Telisa Formation in the South Sumatra Basin was carried out to identify the potential shale gas distribution. The objective of this paper is to characterize the core sample by analyzing the total organic carbon (TOC) content, kerogen type and thermal maturity of shale gas layers in terms of vertical resolution based on log data from four well log data. In addition, a seismic interpretation approach including a seismic attribute analysis and an inverted acoustic impedance is explored to spatially distribute the shale gas potential based on TOC values. Geochemical assessment of the Telisa shale gas reservoir revealed that the organic richness of the reservoir is classified as fair to good in quality. Kerogen type in the reservoir is considered a mixture of type II/III (oil/gas prone) to type III (gas prone). In terms of maturity, the Telisa shale gas reservoir is categorized as “in a mature stage”, representing an oil window up to a wet gas window. The prospective reservoir distribution is indicated by a shale lithology characterized by a high acoustic impedance range of 20,000–24,000 ft/s g/cc. In contrast, the organic richness of the Telisa shale reservoir is classified as “of fair quality”, with TOC in the range of 0.75–1 wt%.

Geothermal energy is able to provide a cheap, safe and reliable approach to fulfill the energy requirement. Hot dry rock (HDR) geothermal energy can generate large scale energy on durable basis. To utilize this energy, enhanced geothermal systems (EGS) are used which evolve energy from deep seated (3–7 km) geothermal resources. The major cost in this type of power plant is that of drilling a bore-hole. The aim of this study is to utilize the already-drilled exploratory, dry and abandoned oil and gas wells of Pakistan. About 60% of total wells drilled in Pakistan are non-producing. Analyses of different zones are marked according to thermal range distribution, whereas the binary system power plant can be built on commercial scale. The current study also demonstrates the power-production system for economical electricity generation at three diverse source temperatures and concludes that a 12 in. borehole heat exchanger, at a depth of 3 km, can extract suitable energy to run a 3.2 MW turbine. The current study not only cures all the loss of petroleum industry but also proposes a method to overcome the required energy demands as well.

A well deliverability equation is important to measure production capabilities under certain conditions of reservoirs’ and bottom hole flowing pressures. Therefore, this work offered a gas deliverability equation for the Siba Gas Condensate Field in Iraq, particularly for the Yamama reservoir formation. The equation was obtained according to the methods of Houpert and Rawlins–Schellhardt for pressure-squared and pseudo pressure techniques. Results revealed that despite the lack of relevant information, the obtained deliverability equation was acceptable with mean absolute percentage errors (MAPEs) equal to 0.145053, 0.054328, 0.050463, and 0.046233, relative to available measured data. A generalized inflow performance relationship (IPR) from the literature was chosen for verification and comparison. Good and acceptable results were obtained with MAPEs equal to 0.001102726 and 0.001052612. A future IPR was derived to predict the flow behavior of the target reservoir production with a range of reservoir pressures no less than the current reservoir pressure of 8593 psia. The prediction was aimed at avoiding the loss of a significant amount of condensate in the reservoir because its measured dew point pressure is equal to 9021.35 psia. The constructed future IPR was compared with the generalized future IPR, and both showed good agreement with a MAPE equal to 5.234%.

Oil-rim reservoirs are considered as some of the unconventional reservoirs in which a thin oil layer, a thick gas cap and an aquifer layer are involved. The economic prosperity of drilling this type of reservoirs, involves novel enhanced oil recovery techniques to produce more oil volume. Production from oil-rim reservoirs would be a particular challenge due to their unique characterization. In this comprehensive study, we simulate six different scenarios with drilling new wells horizontally or vertically on the oil recovery enhancement for selecting the optimum technique which has more compatibility with the reservoir characteristics. Moreover, another objective of this study is to investigate the dominant influence of simulation procedures in each scenario on the key parameters of gas/oil ratio, water cut and, pressure drop. The drilling of a horizontal well (and its potential contact with the reservoir) results in the best performance among other scenarios, and scenarios of drilling new vertical wells have yielded excellent results for commencing the production operation.

This study aims to establish a group of heterogeneous organic compounds of porphyrin and derived compounds. This is useful for many medical fields such as phototherapy or industrial therapy, namely dyes and OLED screens. On this basis, we assembled a group of six compounds and a group of their compounds with different metals (Zn, Co, Cu, Fe and Pd) and studied their properties by spectral methods. We conducted an electrochemical study through the voltmeter ring to study the effect of alternatives and of the metal quality on the oxidation for a group of six porphyrin compounds, which enabled us to study future applications for vehicles obtained and developed in OLED, organic light emitting Diodes technology.