Reservoir Fluid Properties Research Articles

Активизация пластовой микрофлоры для повышения нефтеотдачи

Constant optimization of technological processes of oil production is one of the integral parts of rational subsurface use. The study and implementation of new developments and technologies in the oil production process is primarily due to the economic effect. Methods of increasing oil recovery are of particular interest in the practical implementation of innovative technologies in the oil and gas industry. To date, a huge number of technologies have been developed and tested in field conditions aimed at preserving and increasing the volume of produced products, the classification of which is very diverse. The primary criteria for choosing a method or combination of methods of influencing a productive reservoir in order to increase oil recovery are the geological conditions of the productive horizon, as well as the composition and physico-chemical properties of reservoir fluids. Currently, of all the many methods of increasing oil recovery, the microbiological method is the least studied, as a result of which it is extremely rarely used in enterprises. The relevance of research on the effects of microorganisms on the reservoir rock is beyond doubt. The possibility of widespread application of oil recovery enhancement technology based on bacterial life processes is interesting both from the point of view of environmental safety and economic efficiency. One of the microbiological methods of increasing oil recovery is the activation of the existing reservoir microflora by feeding a nutrient medium into the reservoir. In the course of their vital activity, some types of bacteria are capable of destroying clay rocks, which entails changes in the filtration and capacitance properties of the reservoir rock and, as a result, the volume of products produced increases significantly. The advantage of this method is the absence of the need for forced “contamination” of the reservoir formation, since the necessary bacteria are already in it.

تصميم نظام غمر المياه لحقل الدفا النفطي

Currently, water-flooding is responsible for a big portion of world oil production. The vertical sweep efficiency and the areal coverage each of these requires careful sampling to get represented reservoir rock and fluid properties measures of reservoir heterogeneity, Economically, a pilot is a desirable tool for studying oil recovery performance on reservoir sample and then scaled up to yield the performance to be expected from field performance. Defa field was produced since 1968 with good oil flow rate reaching 200,000 BOPD but during the life of the field, the production decreased to 50,000 BOPD in 2001. So, this study was conducted to increase oil production by add some energy to the reservoir to increase average reservoir pressure and try to maintain it to initial pressure and to increase displacement and sweep efficiency. The water flooding design was implemented in sector model in the Defa field using five spots pattern. The study was performed by using Excel and Water Drive software to achieve a good water flooding design. When comparing the results obtained from two calculation methods, the minimum error was equal 0.03 percent and the maximum error was around 12 percent. So, the results were acceptable and the process was recommended to the Defa-field. Keywords: Water flooding; Software; Fractional Flow, Break through.

The Time-Varying Characteristics of Relative Permeability in Oil Reservoirs with Gas Injection

Relative permeability is a critical parameter in reservoir numerical simulation and production prediction, intimately associated with reservoir architecture and fluid property. During gas injection development, substantial alterations in reservoir properties and fluid phase behavior induce dynamic changes in relative permeability. Clearly characterizing the time-varying features of relative permeability is very useful for an understanding of how gas injection influences fluid mobility within the reservoir and enhances recovery rates. In this paper, core displacement experiments are firstly conducted to obtain the characteristics of the relative permeability of oil and gas under various development stages and displacement conditions, further delineating the comprehensive shifts in reservoir properties at different gas injection stages. Subsequently, a novel reservoir numerical simulation method is proposed that considers the spatial and temporal segmentation of relative permeability curves in the reservoir simulation. Finally, a practical application is presented to clarify the effects of injection and production parameters on the development performance of gas flooding oil reservoirs. The results show the following: (i) Significant time-varying characteristics of relative permeability occur throughout gas injection development, in the early stages of gas injection, where most of the reservoir is at the gas injection front, and a rightward shift in relative oil and gas permeability indicates that gas injection promotes oil mobility. Conversely, in the later stages of gas injection, as the reservoir reaches the trailing edge of gas injection, the change trend in relative oil and gas permeability reverses, shifting leftward, thereby exacerbating the gas breakout phenomena. (ii) Increasing the rate of gas injection causes relative oil and gas permeability to move leftward, effectively enhancing the gas volume sweep coefficient and microscopic oil displacement efficiency at lower injection speeds while reducing development performance at higher injection speeds. (iii) An increase in gas injection pressure causes relative oil and gas permeability to shift rightward, and although it reduces residual oil saturation and enhances microscopic oil displacement efficiency, it also intensifies gas breakout phenomena and lowers the gas volume sweep coefficient. This paper provides theoretical guidance and technical support for the design of gas injection strategies, optimization of injection and production parameters, and production forecasting.

Recognition of Artificial Gases Formed during Drill-Bit Metamorphism Using Advanced Mud Gas

Drill-bit metamorphism (DBM) is the process of thermal degradation of drilling fluid at the interface of the bit and rock due to the overheating of the bit. The heat generated by the drill when drilling into a rock formation promotes the generation of artificial hydrocarbon and non-hydrocarbon gas, changing the composition of the gas. The objective of this work is to recognize and evaluate artificial gases originating from DBM in wells targeting oil accumulations in pre-salt carbonates in the Santos Basin, Brazil. For the evaluation, chromatographic data from advanced mud gas equipment, drilling parameters, drill type, and lithology were used. The molar concentrations of gases and gas ratios (especially ethene/ethene+ethane and dryness) were analyzed, which identified the occurrence of DBM. DBM is most severe when wells penetrate igneous and carbonate rocks with diamond-impregnated drill bits. The rate of penetration, weight on bit, and rotation per minute were evaluated together with gas data but did not present good correlations to assist in identifying DBM. The depth intervals over which artificial gases formed during DBM are recognized should not be used to infer pay zones or predict the composition and properties of reservoir fluids because the gas composition is completely changed.

Modifying the Effects around the Well can have an Impact on the Drilling Process

Environmental changes around a well can significantly affect the drilling process. This paper examines the effects of flow rate, bottomhole pressure, sheet permeability, viscosity, pressure gradient and well radius on the drilling process. It is shown that the energy-dynamic instability of the sheet’s near-shiva space, a highly active region in the formation, leads to changes in reservoir rock and fluid properties during the drilling process. These changes include physicochemical transformations such as deposition of asphaltenes, paraffins, and resins, as well as swelling of clay particles, which can disrupt reservoir physical properties and affect hydrocarbon flow. In addition, completion and production techniques and the chemistry of drilling and pressure fluids are particularly critical for low-permeability reservoirs. In this paper, the concept of skin effect is also introduced to assess the impact of process fluids on the bottomhole region, and a new assessment model is proposed. The results of the study are important for improving drilling technology and optimising reservoir development.

Study on fluid phase behavior characteristics of low permeability reservoir under different CO2 injection amounts

M reservoir is a low peremeability reservoir located in northwest China. Currently, it faces the problem of difficult water injection, low single well production, and rapid production decline. CO2 flooding technology is considered to be implemented to solve these problems by effectively supplementing formation energy. Considering that the phase behavior of reservoir fluid during CO2 injection and its influence on the development effect are complex, the PVT test experiment of reservoir fluid is carried out to analyze the variation of reservoir fluid properties under different CO2 injection volumes. The experimental results show that the saturation pressure, solution gas-oil ratio, volume coefficient and expansion coefficient of crude oil increase with the increase of CO2 injection, while the viscosity and density of oil continue to decrease. When the CO2 injection amount reaches 32 %, the dissolved gas-oil ratio increases from the original 36.2 m³/m³to 150.2 m³/m³, the viscosity of the formation oil is reduced by about 76 % than before CO2 injection; and the volume of crude oil has expanded to 1.28 times of that without CO2 injection. Moreover, the P-T phase diagram is drawn and the influence of CO2 injection on the distribution of phase regions in the phase diagram and the critical parameters of oil is analyzed. The high pressure physical properties of reservoir fluids at different CO2 injection volumes are obtained, which can provide a good foundation for the study of enhancing oil recovery by CO2 injection in M reservoir.

Multi-scale nonlinear reservoir flow simulation based on digital core reconstruction

During the exploitation of oil and gas reservoirs, changes in reservoir physical or fluid properties will lead to alterations in formation seepage capacity, subsequently impacting the productivity of oil and gas wells. Therefore, it is crucial to evaluate the variations in reservoir physical and fluid properties as well as their influence on oil and gas well productivity during reservoir exploitation.It employs a descriptive approach to investigate cross-scale (i.e., micro-scale → small-scale → large-scale) fluid seepage phenomena in water flooding. By leveraging digital core reconstruction technology and focusing on micro-pore network simulation, it establishes an analytical framework for studying cross-scale seepage fields, facilitating the exploration of the micro-seepage mechanism that governs non-homogeneous water flooding's impact on liquid production capacity within a reservoir. Integrating constraints from micro-pore network simulation and small-scale core displacement test data, while considering macro-heterogeneity near wellbore areas as flow unit divisions and superposition bases within large-scale reservoirs, it reveals the nonlinear flow characteristics of changes in liquid production capacity in water-flooding oil reservoirs based on microscopic digital core analysis. This approach aligns with findings from small-scale core testing and sweep coefficient correction while also addressing the non-uniform distribution characteristics of physical parameters within large-scale reservoirs.By integrating permeability field characteristics at three levels, this approach optimizes its technical advantages in describing dynamic permeability fields at each level, thereby facilitating precise prediction of water drive oil development effects.

Identification of Multi-Parameter Fluid in Igneous Rock Reservoir Logging—A Case Study of PL9-1 in Bohai Oilfield

Since the “13th Five-Year Plan”, the exploration of large-scale structural oil and gas reservoirs in the Bohai oilfield has become more complex, and the exploration of igneous oil and gas reservoirs has become the focus of current attention. At present, igneous rock reservoir fluid identification methods are mainly based on the evaluation method of logging single parameter construction, which is primarily a qualitative identification due to lithology, physical property, and engineering factors. Accurate acquisition of interference logging data, and multi-parameter coupling and recording coupling methods are few, lacking systematic and comprehensive evaluation and analysis of logging data. Since conventional logging data in the study area have difficulty accurately and quickly identifying reservoir fluid properties, a systematic analysis was conducted of three factors: lithology, physical properties, and engineering, as well as a variety of logging parameters (gas measurement, three-dimensional quantitative fluorescence, geochemical, FLAIR, etc.) that can reflect fluid properties were integrated. Based on parameter sensitivity analysis, the quantitative characterization index FI of multi-parameter coupling fluid identification was established using the data from testing, sampling, and laboratory testing to develop the identification standard. The sensitivity analysis and optimization of characteristic parameters were carried out by integrating the data reflecting fluid properties such as gas surveys, geochemical data, and related logging data. Combined with gas logging-derived parameters and improved engineering parameters (the value of alkanes released by rock cracking per unit volume Cadjust, C1 abnormal multiple values, three-dimensional quantitative fluorescence correlation factor N), the fluid properties were identified, evaluation factors were constructed based on factor analysis, and fluid identification interactive charts were established. By analyzing test wells in the PL9-1 well area, the results of comparison test data are more reliable. Compared with conventional methods, this method reduces the dependence of a single parameter by synthesizing multiple parameters and reduces the influence of lithology, physical properties, and engineering parameters on fluid identification. It is more reasonable and practical. It can accurately and quickly identify the fluid properties of igneous rock reservoirs in the study area. It has a guiding significance for improving the accurate evaluation of logging data and increasing exploration benefits.

A hybrid modeling approach: dynamic simulation of two-phase fluid flow in compacting gas condensate reservoirs using potential flow theory

Simulating the flow processes of complex hydrocarbon mixtures, such as gas condensate mixtures and volatile oils, in deep reservoirs is one of the most challenging problems in reservoir hydrodynamics. The challenge lies in meeting three requirements simultaneously when creating a simulator: high accuracy, low computational cost, and high reliability. These metrics determine the performance of the simulation. Meeting all these requirements at the same time necessitates a hybrid approach to solving the problem and optimizing the computational algorithm in terms of CPU time. A new technique has been developed for hybrid modeling of the development of deposits of complex hydrocarbon mixtures. This technique integrates the theory of potential flow, the Binary Flow Model (which accounts for rock compaction, PVT properties of reservoir fluids, phase transformation, and mass transfer between phases), and the material balance equations of the hydrocarbon system using time discretization. In this case, to linearize nonlinear differential equations for the flow of a gascondensate mixture, the method of averaging reservoir pressure along the radial coordinate was used. By introducing the Khrestianovich function, an algorithm was obtained to determine the rate of inflow of the gas-condensate mixture to the well. Using material balance equations for gas and condensate, it was possible to obtain differential equations that describe changes in reservoir pressure and condensate saturation over time. Based on this technique, a simulator for a gas condensate reservoir was created, enabling computer studies to be conducted. The results demonstrated the proposed technique's good accuracy compared with the results of the semi-analytical solution. Keywords: dynamic modeling; simulation; monitoring; streamline; hybrid modeling; binary model.

Optimized artificial neural network application for estimating oil recovery factor of solution gas drive sandstone reservoirs

The most crucial aspect in determining field development plans is the oil recovery factor (RF). However, RF has a complex relationship with the reservoir rock and fluid properties. The application of artificial neural networks is able to produce complex correlations between reservoir parameters that affect the recovery factor. This research provides a new approach to improve the accuracy of the ANN model in the form of steps including removing outlier data, selecting input parameters, selecting transferring functions, selecting the number of neurons, and determining hidden layers. By applying these steps, an ANN model was selected with nine input parameters consisting of oil viscosity, water saturation, initial oil formation volume factor, formation thickness, initial pressure, permeability, specific gravity of oil, porosity, and original oil in place. Furthermore, based on the correlation coefficient, a tangent sigmoid transferring function, 30 neurons, and two hidden layers were determined. The proposed ANN correlation gives the best accuracy compared to the previous correlations. This is proved by the highest correlation coefficient of 0.91657.

Volatile light hydrocarbons as thermal and alteration indicators in oil and gas fields

Volatile light hydrocarbons (VLH) are an essential component of reservoir petroleum fluids. Understanding of their origin and fate is crucial not only in exploration but increasingly also in petroleum engineering, as this greatly impacts fluid typing, proper mapping, recoverability and economic value. Due to their sensitivity to subsurface thermal stress and geological alteration processes, their proper characterisation holds promise to understanding the thermal conditions under which petroleum fluids were generated and subsequent fluid modifications during migration and within the reservoir. To study the behaviour of these hydrocarbons under different geological conditions we selected oil and gas fields from two giant conventional petroleum systems in the Arabian Peninsula collectively spanning the entire petroleum spectrum from heavy oil to dry and sour gas. In situ representative bottomhole or recombined pressure–volume–temperature (PVT) fluid composition data were constrained with molecular and stable carbon isotope geochemistry in key wells. Systematic covariance among the slope factor (SF) of propane to pentane and the isomer ratios of butane and pentane with reservoir engineering and geochemical variables in well-constrained black oil to gas condensate petroleum systems allowed the derivation of three formulas to calculate thermal maturity in terms of vitrinite reflectance equivalent from VLH fluid composition: (1) %VRe(SF) = 0.38 SF + 0.41, (2) %VRe(i4) = 1.70 (iC4/nC4) + 0.61, and (3) %VRe(i5) = 0.89 (iC5/nC5) + 0.56. The slope factor, iC4/nC4, and iC5/nC5 ratios all increase monotonically with the thermal evolution of unaltered fluids, allowing for effective application of their derived %VRe formulas across the entire unaltered fluid spectrum, from heavy oil to dry gas. Deviations from indigenous-fluid trends do occur for fluids altered by phase separation, biodegradation, thermal cracking, and thermochemical sulfate reduction (TSR), but corrections can be made to minimize uncertainty in assessing true thermal maturity of altered fluids while respecting other reservoir fluid properties such as gas-to-oil ratio (GOR) and saturation pressure relationships. For instance, although a single charge that has been phase fractionated yields fluids with variable GORs, saturation pressures and slope factors, their butane and pentane isomer ratios remain reflective of the original fluid maturity. In contrast, biodegradation-induced overestimation of maturity based on the isomer ratios of butane and pentane can be corrected by the less affected SF-derived maturity parameter. Reversal to lower apparent SF-derived maturity in thermally and TSR cracked fluids can, on the other hand, be corrected by considering the less affected butane and pentane isomer ratios. Overall, maturities calculated using VLH composition correspond well with fluid type defined based on phase behaviour and source-rock kinetics, thereby putting forward new tools to quantify thermal maturity of reservoir fluids that may be applicable in other petroleum systems.

A comprehensive review of cased hole sand control optimization techniques: Theoretical and practical perspectives

Cased hole sand control is a critical aspect of oil and gas well management, ensuring efficient production by mitigating sand production issues. This review presents a comprehensive review of cased hole sand control optimization techniques, offering theoretical insights and practical perspectives to enhance well productivity and longevity. The review encompasses various aspects, including the challenges of sand production, the importance of sand control, and the evolution of sand control techniques. Sand production in oil and gas wells can lead to equipment damage, wellbore instability, and reduced production efficiency. Effective sand control is thus essential to maintain well integrity and maximize hydrocarbon recovery. This review explores the fundamental principles of sand control, highlighting the key parameters influencing sand production, such as reservoir properties, fluid properties, and wellbore geometry. The review discusses traditional sand control methods, such as gravel packing and standalone screens, along with emerging technologies like expandable sand screens and autonomous inflow control devices. It evaluates the advantages and limitations of each technique, considering factors such as installation complexity, cost-effectiveness, and long-term reliability. Furthermore, the review delves into advanced sand control optimization strategies, including the use of modeling and simulation tools to predict sand production and optimize sand control design. It discusses the integration of data analytics and machine learning techniques for real-time monitoring and decision-making, enhancing sand control effectiveness and reducing operational risks. Practical case studies and field applications are presented to illustrate the implementation of sand control optimization techniques in real-world scenarios. These case studies highlight the challenges faced, the solutions implemented, and the outcomes achieved, providing valuable insights for industry practitioners and researchers. In conclusion, this review provides a comprehensive overview of cased hole sand control optimization techniques, emphasizing the importance of integrating theoretical knowledge with practical considerations to enhance sand control efficiency and maximize well productivity. his review paper will systematically analyze existing methodologies and the latest advancements in cased hole sand control treatments. It explores theoretical frameworks, compares practical outcomes, and discusses the implications of optimized frac geometries for reservoir performance enhancement across varied geological settings.

Equinor Leads Project To Turn Ubiquitous Drill Cuttings Into Precious PVT Samples

They were told it wouldn’t work. But in a new study, experts at Equinor and Applied Petroleum Technology (APT) suggest they are on the brink of using contaminated drill cuttings to predict critical reservoir fluid properties. The two Norwegian firms believe their project will soon make it possible to treat cuttings, collected from each well, as if they were pressure/volume/temperature (PVT) samples, which are collected from a significantly smaller share of wells due to the risks and high cost of doing so. Since its inception in 1972, Equinor has drilled over 5,000 offshore wells, from which just over 2,000 PVT samples have been gathered. Given that only two or three good samples are taken from most wells—almost always exploration wells—a significant data gap exists for the remainder, most of which are the subsequent development wells. And each year, Equinor drills around 20 to 25 new wells, mostly near existing platforms. If oil and gas firms could obtain PVT-like results from cuttings alone, they would presumably gain more precise guidance on where to place new wells along with insights on facility/topside design, reservoir management, and eventually on the plugging and abandonment phase. The big obstacle Equinor and APT are trying to surmount centers on how rock cuttings are soaked in oil-based muds (OBMs) as they circulate up the wellbore before being collected from a shale shaker. The oil ends up masking the reservoir’s hydrocarbons, rendering traditional geochemistry methods ineffective. What Equinor has shown in its study is that problem can be circumvented to obtain reliable estimates of API gravity and viscosity, two defining aspects of reservoir fluid quality and flow potential. Several more outputs are in the works. Tao Yang, an industry-recognized reservoir expert and chief professional at Equinor, said when he spoke with geochemists in the company about the project nearly 2 years ago, they were decidedly dubious. “They gave us a warning at the beginning and said that this was a very difficult area, that the cuttings were too dirty, and that we probably wouldn’t get anything out of them,” he said. But what few in the upstream industry knew at the time is that there existed a technology that can overcome the contamination issue—and it has been around for decades. Invented in the 1960s, gel permeation chromatography (GPC) coupled with ultraviolet (UV) absorbance detection, or simply GPC-UV, is used primarily by the chemicals sector for polymer analysis. The GPC aspect separates molecules based on their size as they flow through a gel-filled column. The smaller molecules take the longest to pass through while the larger molecules move more rapidly—the opposite of how most geochemistry assays work. As the molecules move down the column, they are exposed to UV light. Depending on their chemical structure, each molecule will absorb light at varying intensities which in turn can be measured and used to detect the presence of various compounds, including those indicative of oil.

Reservoir Prediction and Prospectivity of Omos Field Onshore Niger Delta Basin, Nigeria

Reservoir prediction and prospectivity are performance indices of the oil and gas field development planning and reserves estimation which depicts the behaviour of the reservoir in the future; its success is dependent on accurate description of the reservoir rock properties, fluid properties, rock-fluid properties and flow. Hence, the objective of this paper was to investigate and predict the reservoir and prospectivity of Omos Field, Onshore Niger Delta Basin, by integrating appropriate standard methods. Results obtained from rock physics attribute map analysis revealed very high Mu-Rho values between 13.0-16.2 Gpa, that is expected for sand presence, and this agrees with the good quality reservoir sands predicted from sequence stratigraphy study.Lambda-Rho values obtained ranges between - 1 to 9.5 GPa, with a much lower value between -1 to 4.3 in the prospective zone that indicates the presence of hydrocarbon bearing sand. These results agree with the results of structural and amplitude maps analysis. Hence the prospective reservoir has a very good hydrocarbon potential in this zone and should be a target for further appraisal for development and production purposes.

Flowing Bottomhole Pressure during Gas Lift in Unconventional Oil Wells

Summary We present artificial neural network (ANN) models for predicting the flowing bottomhole pressure (FBHP) of unconventional oil wells under gas lift operations. Well parameters, fluid properties, production/injection data, and bottomhole gauge pressures from 16 shale oil wells in Permian Basin, Texas, USA, are analyzed to determine key parameters affecting FBHP during the gas lift operation. For the reservoir fluid properties, several pressure-volume-temperature (PVT) models, such as Benedict-Webb-Rubin (BWR); Lee, Gonzalez, and Eakin; and Standing, among others, are examined against experimentally tuned fluid properties (i.e., viscosity, formation volume factor, and solution gas-oil ratio) to identify representative fluid (PVT) models for oil and gas properties. Pipe flow models (i.e., Hagedorn and Brown; Gray, Begs and Brill; and Petalas and Aziz) are also examined by comparing calculated FBHP against the bottomhole gauge pressures to identify a representative pipe flow model. Training and test data sets are then generated using the representative PVT and pipe flow models to develop a physics-based ANN model. The physics-based ANN model inputs are hydrocarbon fluid properties, liquid flow rate (qL), gas-liquid ratio (GLR), water-oil ratio (WOR), well true vertical depth (TVD), wellhead pressure (Pwh), wellhead temperature (Twh), and temperature gradient (dT/dh). A data-based ANN model is also developed based on only TVD, Pwh, qL, GLR, and WOR. Both physics- and data-based ANN models are trained through hyperparameter optimization using genetic algorithm and K-fold validation and then tested against the gauge FBHP. The results reveal that both models perform well with the FBHP prediction from field data with a normalized mean absolute error (NMAE) of around 10%. However, a comparison between results from the physics- and data-based ANN models shows that the accuracy of the physics-based model is higher at the later phase of the gas lift operation when the steady-state pipe flow is well established. On the contrary, the data-based model performs better for the early phase of gas lift operation when transient flow behavior is dominant. Developed ANN models and workflows can be applied to optimize gas lift operations under different fluid and well conditions.

Modeling of Quantitative Characterization Parameters and Identification of Fluid Properties in Tight Sandstone Reservoirs of the Ordos Basin

Modeling of Quantitative Characterization Parameters and Identification of Fluid Properties in Tight Sandstone Reservoirs of the Ordos Basin

A Case Study of Synchrosqueezing Wavelet Transform to Conventional Logging

In this paper, the synchronous squeezing wavelet transform (SSWT) is used to process the conventional logging curve, and the spectral characteristics of logging signal are obtained. The results show that the spectral characteristics of SSWT logging in tight sandstone reservoir are more obvious than that in depth domain, and have different characteristics for different reservoir fluid properties, which is helpful to identify the fluid properties of complex reservoirs.

Holistic Evaluation of Reservoir Oil Viscosity in Breidablikk Field – Including Mud Gas Logging Approach

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).

Investigating the impact of pulsed plasma-based shockwave technology on the characteristics of Indian crude oil

The declining production from oil wells has become a growing concern worldwide, primarily because conventional methods are becoming less efficient in extracting the original oil reserves. Due to limitations associated with traditional oil recovery techniques, including their high expenses, depth limitations, heat losses, instability of additives, and environmental hazards, it is imperative to investigate the impact of alternative technologies on reservoir fluid properties and recovery. This research proposes a pulse plasma-based shockwave technology (PPBSW) using an indigenously developed tool that uses repeated electrohydraulic shock waves. The liquid pulsed discharge's plasma channel rapidly expands causing an electrohydraulic shock wave. The crude oil samples were exposed using repeated, steep-fronted shock waves of high strength. Crude oil samples were obtained from the Indian Oilfield and underwent characterization both before and after exposure to shockwaves. After the shockwave treatment, there were observable changes in the weight percentages of wax, saturates, aromatics, resins, and asphaltenes in the composition of the oil. C13 NMR investigations reveals that MCL (mean chain length) of the exposed samples was slightly affected. Further, the impact of shock wave on the viscosity of the crude oil was evaluated and viscosity of the samples found to be altered after exposure. Oil recovery was evaluated using core flooding studies on a saturated Berea sandstone core. The core was saturated using core plug saturator at 1000 psi. As a result of altered viscosity and reduced interactions between the rock and fluid, the oil recovery from the treated samples was approximately 24% greater as compared to the untreated samples. Given the oil recovery and mixed effect on the viscosity of studied crude oil samples, it can be inferred that PPBSW has a favourable effect on the hydrocarbon recovery.

Gas Compressibility Factor Prediction Using Machining Learning Algorithmic Protocol for Niger – Delta Gas Reservoir

The gas compressibility factor also known as Z-factor plays an important role in obtaining thermodynamic properties of natural gas reservoir fluid property. Typically, empirical correlations and complex equation of state have been applied to determine this parameter in absence of laboratory measurements. However, high cost of running experimental measurement, poor performance and some limitations associated with these existing correlations have made the researchers to use intelligent models instead. Therefore, this study aimed at adopting support vector machine algorithm to forecast gas compressibility factor and to validate its performance with predictions from Artificial Neural network (ANN) and some existing correlations using statistical and performance plot analysis. A total of 519 data sets from Niger Delta was used in developing the model, out of it, 70 percent was used for training, 20 percent for testing and 10 percent for validation using MATLAB tool. From the statistical analysis result, it was observed that the new developed model did better than other existing methods with numerical value of 0.1997 rank, 0.0009 mean absolute error and 0.98 of coefficient of correlation using the test data. The cross plot of the support vector machine model gave the tightest cloud along 45o reference line. The residual (error) associated with the performance was impressive which was done to observe the distribution and the interval at which the error is minimal.