Hydrocarbon Recovery Research Articles

On the issue of injection of CO2 into a gas-condensate deposit within the framework of the technology of extraction of oil and retrograde condensate at concentrations below the filtration threshold from gas-saturated oil and gas source deposits of oil and gas condensate fields, at the late stage of development

The study was carried out as part of the work on the hydrodynamic justification of the technology for extracting oil and retrograde condensate at concentrations below the filtration threshold from gas-saturated oil and gas source deposits of oil and gas condensate fields, at the late stages of development. On the basis of a test multicomponent model using the key parameters of the Vuktyl oil and gas condensate field, it is shown that the injection of carbon dioxide, for the early replacement of the “dry” gas injected at the previous stage, entails risks of reducing the liquid hydrocarbon recovery factor and the risks of precipitation of asphaltene-paraffin deposits.

Dolomite dissolution and porosity enhancement simulation with acetic acid: Insights into the influence of temperature and ionic effects

Dolostone reservoirs are crucial for global oil and gas storage, holding a significant portion of hydrocarbon reserves within carbonate formations. Understanding the chemical mechanism of dolomite dissolution with organic acids and associated porosity development in these reservoirs is vital for optimizing hydrocarbon recovery. In this work, two sets of simulation experiments are designed to understand the controls of temperature and ionic effects on porosity enhancement during the dissolution of dolomite with acetic acid. In specific, we discovered a three-step reaction process between dolomite and acetic acid, involving acetic acid dissolution in water, acetic acid dissociation, and dolomite dissolution. Burial environments with higher temperatures reduce the degree of acetic acid dissociation, leading to a corresponding decrease in dolomite dissolution in acetic acid solutions. The presence of salt ions in the solution influences the reaction process, with magnesium chloride (MgCl2) having the most significant enhancing effect on dolomite dissolution, followed by sodium chloride (NaCl), while calcium chloride (CaCl2) has a limited impact. Sodium sulfate (Na2SO4) enhances dolomite dissolution at lower temperatures; however, at higher temperatures (>100 °C), it may reduce dolomite dissolution due to the precipitation of CaSO4. Despite a relatively short open-flow time, episodic burial dissolution of dolomite by acetic acid fluids under overburden pressure leads to a "net increase" in the reservoir space and enhances its connectivity attributes. During burial diagenesis, geological forces episodically drive organic acid fluids to the dolomite reservoir, predominantly dissolving dolomite along pre-existing pore development zones and geological interfaces, exhibiting inheritance, episodicity, and localization characteristics. Overall, this study provides insights into the dissolution and diagenetic processes of dolomite in the presence under acetic acids, from the point of dissolution simulation experiments. Collectively, these findings enhance our understanding of pore-system evolution and fluid-rock interactions in deep carbonate reservoirs.

Impact of Methylene Blue on Enhancing the Hydrocarbon Potential of Early Cambrian Khewra Sandstone Formation from the Potwar Basin, Pakistan.

Significant amounts of hydrocarbon resources are left behind after primary and secondary recovery processes, necessitating the application of enhanced oil recovery (EOR) techniques for improving the recovery of trapped oil from subsurface formations. In this respect, the wettability of the rock is crucial in assessing the recovery and sweep efficiency of trapped oil. The subsurface reservoirs are inherently contaminated with organic acids, which renders them hydrophobic. Recent research has revealed the significant impacts of nanofluids, surfactants, and methyl orange on altering the wettability of organic-acid-contaminated subsurface formations into the water-wet state. This suggests that the toxic dye methylene blue (MB), which is presently disposed of in huge quantities and contaminates subsurface waters, could be used in EOR. However, the mechanisms behind hydrocarbon recovery using MB solution for attaining hydrophilic conditions are not fully understood. Therefore, the present work examines the impacts of MB on the wettability reversal of organic-acid-contaminated Khewra sandstone samples (obtained from the outcrop in the Potwar Basin, Pakistan) under the downhole temperature and pressure conditions. The sandstone samples are prepared by aging with 10-2 mol/L stearic acid and subsequently treated with various amounts of aqueous MB (10-100 mg/L) for 1 week. Contact angle measurements are then conducted under various physio-thermal conditions (0.1-20 MPa, 25-50 °C, and salinities of 0.1-0.3 M). The results indicate that the Khewra sandstone samples become hydrophobic in the presence of organic acid and under increased pressure, temperature, and salinity. However, the wettability changes from oil-wet to preferentially water-wet in the presence of various MB solutions, thus highlighting the favorable effects of MB on EOR from the Khewra sandstone formation. Moreover, the most significant change in wettability is observed for the Khewra sandstone sample that was aged using 100 mg/L MB. These results suggest that injecting MB into deep underground Khewra sandstone reservoirs may produce more residual hydrocarbons.

A new insight on relative permeability modifier as conformance control in carbonate reservoir

The primary issue of high-water cuts in exploiting carbonate fields poses significant challenges and requires an immediate solution. The approach to tackle the root cause of this problem is reservoir conformance control. Conventional conformance control treatments, such as polymer-based materials, are ineffective and incompatible with the unique properties of carbonate reservoirs. Textural heterogeneity in carbonate leads to heterogeneity in the distribution of storage and flow properties that may govern changes in saturation patterns. The percolation of gas-water flow in carbonate highly depends on the pore structure. Conformance control refers to managing fluid movement within a reservoir to optimize production and reduce unwanted fluid production. The major challenge of water conformance control for carbonates using chemical treatment is the compatibility of the polymer system with the rock and fluid settings. This paper reviews current research on conformance control methods, including chemical and mechanical techniques. The effectiveness of various conformance control methods was evaluated based on their ability to improve sweep efficiency, reduce water production, and increase hydrocarbon recovery in different reservoir types. The review also discusses the challenges of implementing conformance control techniques, such as formation damage and fluid mobility issues. Overall, the paper concludes that successful implementation of conformance control strategies requires a thorough understanding of reservoir characteristics and planning to ensure optimal results. The findings of this study provide valuable insights into developing effective conformance control techniques that can improve hydrocarbon recovery and optimize reservoir performance. The results of this study provide critical insight into using efficient and operationally low-risk materials to reduce water cuts in the strong water drive carbonate reservoir.

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.

A prospect analysis of the Upper Oligocene sandstone reservoirs of the Wenchang 9 block, Pearl River Mouth Basin, northern South China Sea margin

Faults can act as a migration pathway and/or a lateral seal in structural traps in the Wenchang 9 block (WC9B) oil field, affecting the potential for enhanced hydrocarbon recovery in the field. In this study, three-dimensional (3D) seismic survey and well data are used to characterize Upper Oligocene fan delta - tidal flat heterogeneous reservoirs and investigate fault seal potential in two new structural traps interpreted in the WC9B oil field. Five lithofacies are identified in the Upper Oligocene Zhuhai Formation based on the well log analysis and core description. The fan delta front and sand-rich tidal flat sandstone of facies F1 in reservoir unit A of the middle Zhuhai member is characterized by the best porosity and permeability. The RMS amplitude attribute analysis and facies modeling help to predict gradual upward progression of the F1 fan delta deposits from the proximity of the Shenhu Uplift to the NW into the basin for ∼ 7–8 km during accumulation of the middle member. The NE-dipping conjugate normal faults of lower throw in the hanging wall of the NW-dipping main normal basement faults contributed to the formation of hydrocarbon-bearing structural traps and side seals. Two new structural traps in the middle member of Zhuhai Formation interpreted in the WC9B oil field. The traps are 3-way dip closure bounded by the NE-dipping normal faults of the conjugate set that are characterized by good sealing potential in the interval of the middle member. The results of this study contribute to the optimization of the enhanced hydrocarbon recovery of the WC9B oil field.

Estimating hydrocarbon recovery factor at reservoir scale via machine learning: Database-dependent accuracy and reliability

This study aims to estimate recovery factor (RF), a key property for exploration, from other reservoir characteristics, such as porosity, permeability, pressure, and water saturation via machine learning (ML). The database dependence of ML algorithms in the estimation of the hydrocarbon RF at the reservoir scale, however, has not yet been addressed. We, therefore, used various combinations of three databases and applied three regression-based models including the extreme gradient boosting (XGBoost), support vector machine (SVM), and stepwise multiple linear regression (MLR) to construct the ML models and estimate the oil and/or gas RF. Using two databases and the cross-validation method, we evaluated the performance of the ML models. The third independent database was then used to further assess the constructed models. We found that the XGBoost model estimated the oil and gas RF for the train and test datasets more accurately than the SVM and MLR models. In the estimation of oil RF and for the testing dataset in the largest database, we found RMSE = 0.111 for the XGBoost model, while RMSE = 0.130 and 0.134, respectively, for the SVM and MLR models. However, the performance of all the models were unsatisfactory for the independent databases. Results demonstrated that the ML algorithms were highly dependent and sensitive to the databases based on which they were trained. Statistical tests revealed that such unsatisfactory performances were because the distributions of input features and target variables in the train datasets were significantly different from those in the independent databases (p-value <0.05).

Estimation of relative permeability curves in fractured media by coupling pore network modelling and volume of fluid methods

The relative permeability of porous and fractured media is an important concept for various technological applications including hydrocarbon recovery, CO2 sequestration, hydrogen storage, hydrology, and microfluidics. In pore-scale simulations, relative permeability curves can be obtained either by pore-network modelling or direct numerical simulations (e.g., Navier–Stokes based and Lattice Boltzmann methods). While pore network models rely on several conceptual mathematical and geometric simplifications compared to more rigorous direct numerical methods, pore network modelling is often the only option to conduct the fast numerical simulation at a core-scale and regular desktop PC within a reasonable time frame. In this study, we analyse the ability of the developed hybrid pore network modelling and volume of fluid methods (VOF–PNM) model to accurately predict the two-phase flow displacement in a ramified system of fractures. This is done by conducting a number of 2D and 3D two-phase flow simulations with different viscosity ratios, contact angles, and capillary numbers. The VOF–PNM output with respect to history-matched relative permeability and capillary pressure curves is then compared to the reference conventional VOF simulations using a range of validation metrics. Such benchmarking allows concluding that the developed VOF–PNM solver can model flow through a system of fractures with an acceptable accuracy compared to the widely used VOF method. In turn, the conventional dynamic PNM algorithm failed to match the relative permeability and capillary pressure when compared to the reference VOF simulations. In terms of computational time, the non-parallelised hybrid VOF–PNM model is at least two orders of magnitude faster than parallelised VOF simulation and only one order of magnitude slower than the conventional dynamic PNM algorithm. The findings are beneficial for simulating two-phase flow through a fractured system at a core scale, as a design tool for microfluidic devices, and for further evolution of the VOF–PNM model into a comprehensive tool for transient multi-scale multi-physics simulations in coal.

Wettability effect on displacement in disordered media under preferential flow conditions

Preferential flow in a porous medium is commonly encountered in many practical applications. Our previous studies have discovered the preferential flow-induced non-monotonic wettability effect on displacement (J. Fluid Mech, vol. 942, 2022a, R5), but whether this non-monotonic rule is consistent for different disordered media and the impact of the interplay between the disorder and wettability under preferential flow conditions is still not well understood. Here, we combine microfluidic experiments, pore-scale simulations and theoretical analysis to study the impact of the disorder on the invading process where wettability varies from strongly water wet to strongly oil wet. Even though the strongly disordered matrix varies to a uniform state, the generality of the preferential flow-induced non-monotonic wettability effect is still proved. However, the previous pore-scale dynamics based on the strongly disordered matrix cannot explain the invading behaviour in the uniform matrix under preferential flow conditions. New mechanisms for the uniform matrix are further investigated by pore-scale modelling, which indicates that the balance of microscopic imbibition ability and the macroscopic interfacial stability dominate the invading process. We derive a theoretical model to describe the wettability effect and predict the optimal contact angle, which fits well with experimental and simulation results. Our work extends the understanding of the impact of preferential flow conditions on the wettability effect and is also of practical significance for engineering applications, such as geological CO2 sequestration, enhanced hydrocarbon recovery, soil wetting, liquid-infused material fabrication and microfluidic device design.

Exploring Underbalance Drilling: A Comprehensive Review

Underbalance Drilling (UBD) is an advanced drilling technique employed in oil and gas industry to improve well productivity and reduce formation damage. In conventional drilling, overbalance conditions are maintained in order to prevent the influx of formation fluids. In contrast, UBD involves maintaining a hydrostatic pressure lower than the formation pressure during drilling operations. UBD offers several advantages, such as increasing drilling rates, reducing formation damage, improving wellbore stability. By preventing the flow of drilling fluids in to the formation, UBD reduces the risk of formation plugging and improves the recovery of hydrocarbons. This technique is particularly beneficial for depleted reservoirs or formations prone to lost circulation problems. Despite its advantages, proper planning and execution are essential for UBD to manage the associated risks, such as wellbore stability challenges and the potential for unexpected influx of formation fluids. UBD involves the use of specialized equipment such as BOPs, RCDs to manage the hydrostatic pressure of well and control the influx of formation fluids. In conclusion, a comprehensive understanding of UBD is essential for maximizing hydrocarbon recovery alongside a commitment to operational safety and environmental sustainability in the ever- changing landscape of the oil and gas industries.

PROBLEMS OF EVALUATION OF THE EFFICIENCY OF THE STIMULATION OF LOW-PERMEABILITY RESERVOIRS OF HYDROCARBONS

The article discusses the conditions for the formation of hydrocarbon deposits and their changes during the development of lowpermeability reservoirs, as well as the most effective technologies for developing deposits of this type, which help increase the coverage of residual hydrocarbon reserves. Low-permeability reservoirs are susceptible to foreign fluid damage, so it is necessary to continuously reduce damage throughout the fracturing process through the use of optimized fluid systems and process parameters. The most effective technologies are: the use of horizontal wells with multi-stage hydraulic fracturing, which ensures the largest volume of hydrocarbon recovery at the initial stage, the use of multilateral wells with branched horizontal ends when it is impossible to use multi-stage hydraulic fracturing. To increase the connectivity of flow channels and provide increased hydrocarbon production, the multi-stage hydraulic fracturing process damages low-permeability reservoirs. The fracture extends in height and length over tens of meters and, thanks to this, can provide hydrodynamic connection to formation zones remote from the perforation interval. Thus, the need for well research methods that are capable of recording formation performance regardless of the position of the secondary opening (perforation) interval is relevant

The Development of Advanced Fluorescent Tracers Aimed at Drill Cuttings Labelling and Depth Correlation via Injection with Oil-Based Drilling Mud

Fast and precise geo-steering and geo-navigation upon well drilling are the key parameters for improved well targeting, optimal well placement, and maximal hydrocarbon recovery. To advance geo-steering parameters, we propose a new approach to on-site formation evaluation through the use of fluorescent tracers for drill cuttings tagging according to the depth of origin. Cuttings labelling at the drill bit site is followed by near-real-time drilling depth correlation at the well-head via a camera and AI image recognition systems. To suite the drilling process, the engineered tracers should match to the rheology of the utilized drilling mud. This study was performed to comprehensively investigate the effect of fluorescent tracers on the rheological properties of oil-based drilling mud (OBM) and to determine the optimal quantities of the tracers’ addition. We evaluated critical mud characteristics including electrical stability, thixotropic parameters, shear stress, gel strength, plastic viscosity, and yield point as prepared and in the presence of fluorescent tracers at the range of 1 to 20 wt.%. Additionally, the mud’s effects on the long-term stability of the fluorescent tracers were assessed via hot-rolling tests in conditions mimicking downhole conditions, with the aim of determining the tags’ feasibility for drill cuttings labelling applications. The study also examines the recovery potential of the tracers and their reusability in the drilling process. This investigation provides valuable insights into the potential application of fluorescent tracers for downhole drill cuttings depth correlation which will improve geo-steering works.

Features of geophysical monitoring of current oil and gas saturation of productive formations

The process of developing oil and gas fields requires continuous monitoring of the current oil and gas saturation of productive reservoirs. Monitoring the current oil and gas saturation allows for effective hydrocarbon recovery. Solving this problem under the conditions of a cased hole significantly limits the suite of geophysical methods, which are the main source of information about the conditional characteristics of reservoirs. The most effective geophysical methods for determining the current oil and gas saturation of a productive reservoir in a producing well is deemed to be the methods of pulse neutron logging. In this paper, the authors analyzed the features of this method, the geological and technological conditions for its effective application, and identified factors that significantly affect the reliability of log interpretation. The indications of pulse neutron-neutron logging are influenced not only by the geological characteristics of the studied reservoir. During the operation and production of an oil and gas well, technological factors also appear, which often significantly change the methods’ indications. Scientists have identified most of these factors and proposed ways to account for their influence. In their work, the authors focused on two factors that are often neglected when performing logging using pulsed neutron methods, accordingly, and not taking them into account during interpretation often led to misinterpretation of pulsed neutron-neutron logging readings when determining the current oil and gas saturation. There are cases of reservoir contamination during drilling and cementing of the casing, when an unusually large colmatage zone is formed. Or the near-wellbore zone of the reservoir formation is damaged during well operation. Given the limited radial resolution of pulsed neutron methods, an enlargement in the colmatage zone or damaging of the downhole zone of the reservoir during well operation has a significant impact on the method readings. The authors proposed a comprehensive approach that allows avoiding such errors

Application of Young-Laplace with size-dependent contact angle and interfacial tension in shale

Shale has been studied extensively since its hydrocarbon recovery became economical, but there are still uncertainties in the applicability of existing models for characterizing its transport properties. A relevant example is the Young-Laplace equation (YL) for interpreting capillary pressure measurements. This study implements its contact angle and interfacial tension as functions of pore throat size to extend its applicability to shale. This study shows a threshold throat size below which implementing size-dependent (actual) properties is crucial. The threshold size is close to 10 nm. The error of the common approach (fixed contact angle and interfacial tension) increases from 5% to 20% where the throat size decreases from 10 nm to 2 nm.This study applies the actual properties to determine the pore throat size distributions of two shale samples. Implementing actual properties influenced the common interpretations from 20% to 50% of the pore volumes of the samples. This study also quantifies the error of the common approach in calculating the pore-throat size. More importantly, it proposes a simple relation that provides a convenient tool for modifying the existing data to determine the actual pore throat size. The results and the simple relation have applications in characterizing the transport properties of shale formations.

Exploration of Oil/Water/Gas Occurrence State in Shale Reservoir by Molecular Dynamics Simulation

The occurrence state of oil, gas, and water plays a crucial role in exploring shale reservoirs. In this study, molecular dynamics simulations were used to investigate the occurrence states of these fluids in shale nanopores. The results showed that when the alkane is light oil, in narrow pores with a width less than 3 nm, oil molecules exist only in an adsorbed state, whereas both adsorbed and free states exist in larger pores. Due to the stronger interaction of water with the rock surface, the adsorption of oil molecules near the rock is severely prohibited. Oil/water/gas occurrence characteristics in the water-containing pore study indicate that CO2 gas can drive free oil molecules out of the pore, break water bridges, and change the occurrence state of water. During displacement, the gas type affects the oil/gas occurrence state. CO2 has strong adsorption capacity, forming a 1.45 g/cm3 adsorption layer on the rock surface, higher than oil’s density peak of 1.29 g/cm3. Octane solubility in injected gases is CO2 (88.1%) &gt; CH4 (76.8%) &gt; N2 (75.4%), with N2 and CH4 having weak competitive adsorption on the rock. The investigation of different shale reservoir conditions suggests that at high temperature or low pressure, oil/gas molecules are more easily displaced, while at low temperature or high pressure, they are tightly adsorbed to the reservoir rock. These findings contribute to the understanding of fundamental mechanisms governing fluid behavior in shale reservoirs, which could help to develop proper hydrocarbon recovery methods from different oil reservoirs.

Optimal path planning for directional wells across flow units’ many-targets

Over the past decades, directional drilling has continuously advanced to increase hydrocarbon recovery by effectively targeting high-productivity reservoirs. However, many existing approaches primarily focus on heuristic optimization algorithms. Moreover, existing models often neglect the incorporation of petrophysical attributes that can significantly impact the selection of production targets, such as the reservoir quality indicator. This article introduces a novel application of mixed-integer programming to define directional drilling paths, considering practical aspects of interest. The paths are subject to drift angle constraints and reference coordinates that align with the optimal reservoir targets. Such targets are identified using the authors’ proposed technique of maximum closeness centrality and the geologic model of hydraulic flow units. In order to evaluate the effectiveness of this approach, a realistic model of the Campos Basin in Brazil is studied. The results reveal that the highest recovery factors obtained with the proposed methodology (17%) exceed the historical average recovery factor of the studied reservoir (15.66%). We believe this study can contribute to the ongoing efforts to enhance directional drilling and maximize the production potential of offshore oil and gas reservoirs.

Thermodynamic design and experimental study of a condensation recovery system for VOCs

During the storage and transportation process of crude oil on tankers, the light hydrocarbon components in liquid form have the tendency to evaporate and vaporize easily, resulting in wasted resources and environmental pollution. The current petroleum volatile organic compounds (VOCs) recovery system such as absorption and membrane separation applied to crude oil tankers is unable to fulfil the requirements of existing VOCs emission standards. In contrast, the condensation method of VOCs recovery technology has the benefit of a straightforward process principle, and the recovered liquid hydrocarbons can be utilized directly. It is thus vital to develop a condensation recovery system for petroleum VOCs that is compatible with crude oil tankers. To attain the condensation and recovery of the non-azeotropic gases, such as CH4, C2H6, C3H8, and N2 in the feed gas, this paper proposes a low-temperature VOCs condensation recovery system with graded cooling and liquefaction separation for crude oil tankers. The proposed system initially utilizes a R404A/R23 double-stage cascade refrigeration cycle to cool the VOCs below −75 ℃ to liquefy most heavy hydrocarbons. Then, a low-temperature nitrogen expansion cooling cycle is utilized to cool the VOCs to approximately −160 °C to recover the remaining light hydrocarbons. The condensation process is simulated by Aspen HYSYS to study the variable operating conditions. The recovery of total hydrocarbons in the outlet tail gas in the simulation results is analyzed and found to be up to 95.50 %. Under identical refrigeration capacity circumstances, decreasing the inlet pressure, increasing the inlet flow rate, and increasing the methane mole fraction in VOCs component, all lead to declining trends of total hydrocarbon recovery and methane recovery rate. Specifically, the effects of four different hydrocarbon component ratios on total hydrocarbon recovery and total cooling load are investigated at a constant nitrogen content and refrigeration capacity. Furthermore, the optimal design and analysis process for the flow path section of the turbine expander under the cryogenic conditions is discussed. The results demonstrate that the outlet temperature through the turbine expander is at least −172.1 °C, and the cooling capacity can be up to 4.5 kW with a margin of 80 %. Finally, through the comprehensive VOCs condensation recovery experiments, the proposed system successfully achieves the liquefied separation and recovery of CH4, C2H6, and other hydrocarbons. The recovery rate of the total hydrocarbons in the outlet tail gas reaches 96.21 %, conforming to the VOCs emission standards and regulations. The findings of this study provide a viable technical resolution in the field of petroleum VOCs recovery from crude oil tankers.

Deep sequence model-based approach to well log data imputation and petrophysical analysis: A case study on the West Natuna Basin, Indonesia

Well log data imputation is crucial for subsurface geology interpretation, which helps identify the most productive areas for drilling, minimize exploration risks, and maximize hydrocarbon recovery. Obtaining high-quality well data can be challenging due to various issues such as drilling problems, improper logging processes, or operational issues with logging tools. Accurate and reliable imputation methods are essential to address missing or incomplete information in well log data, allowing better decision-making in the oil and gas industry. This study presents a novel well log data imputation method for the West Natuna Basin in Indonesia, using time-series deep learning models. Focusing on the “Kappa” well dataset with missing Vp log data, we trained long short-term memory (LSTM), gated recurrent unit (GRU), and bidirectional LSTM (Bi-LSTM) models using a window-based time step sequence of 10-timesteps intervals as input. The LSTM was observed as the best model, achieving a mean absolute percentage error (MAPE) of about 2.2% and an R-squared (R2) of about 94%. This result suggests that deep sequence model can be effectively used for missing data imputation in well log. Lastly, a petrophysical analysis further underlines the importance of these findings, offering deeper insights into reservoir properties, and value of our research in real-world exploration scenarios. The findings can aid in improving the accuracy and reliability of imputation in well log data, enabling better decision-making in the oil and gas industry.

The main features of compositional modeling algorithms of modern reservoir flow simulators

Modern industrial reservoir flow simulators are integrated software products consisting of several packages. Modeling of gas injection with various compositions, or hydrocarbon recovery from gas-condensate and oil-gas-condensate reservoirs, or thermal recovery methods requires a detailed account for composition of the fluid system. In these cases, compositional (multi-component) flow simulation is used to calculate component distribution between the coexisting phases, the number and the fractions of the phases, together with the flow equations for fluid components.. For this purpose, the flow simulator solves the thermodynamic subproblem using basic methods and algorithms analogous to the fluid modeling (PVT modeling) packages. The paper describes the main principles and specific features of implementation of the compositional modeling algorithms in several modern reservoir flow simulators. Keywords: compositional modeling; multicomponent flow model; reservoir flow simulator; isothermal and non-isothermal compositional modeling.

Enhancement of H2 and light oil production and CO2 emission mitigation during co-pyrolysis of oily sludge and incineration fly ash

The proper treatment and utilization of oily sludge (OS) and incineration fly ash (IFA) remains a significant challenge due to their hazardous nature. To attain effective recovery of petroleum hydrocarbons and synergistic disposal, this study investigated the co-pyrolysis of OS and IFA, resulting in successful energy recovery, CO2 mitigation, and heavy metal immobilization. Results revealed that the peak ratio of light oil to heavy oil fractions reached 179.42% with 20 wt% IFA addition, accompanied by the highest aromatic hydrocarbons selectivity of 30.72% and the lowest coke yield of 106.13 mg/g OS under the optimal temperature of 600 °C. In-depth analysis indicated that IFA inhibited the poly-condensation of macromolecular PAHs and promoted their cracking into light aromatic hydrocarbons. The addition of 50 wt% IFA significantly increased H2 yield (21.02 L/kg OS to 60.95 L/kg OS) and facilitated CO2 sequestration due to its higher content of Ca-bearing minerals. Moreover, high IFA ratios promoted the reduction of Fe species in OS to a low-valence state. Heavy metals in co-pyrolysis char were well immobilized into stable fractions with lower environmental risks. This work highlights the potential of co-pyrolysis as a viable approach for simultaneous disposal of multiple hazardous wastes and offers new insights for their utilization.