Oilfield Production Research Articles

Recent advances on the treatment of oilfield-produced water by advanced oxidation processes: A review

ABSTRACT Despite the advancements in alternative fuels and energy sources, there continues to be a significant global dependence on oil production and extraction. A substantial volume of oilfield-produced water (OPW) is generated during the production and extraction processes of oil fields. Recurrent OPW treatments encountered significant challenges in addressing this particular type of wastewater. Advanced oxidation processes (AOPs) are regarded as a promising alternative approach for the degradation of recalcitrant organic compounds in the OPW. This review focuses on the characterization of OPW. The treatment of organic pollutants in wastewater using AOPs, such as ozonation, Fenton oxidation-based processes, heterogeneous photocatalysis, and persulfate oxidation, is comprehensively reviewed in terms of their efficiency for pollutant degradation. The primary challenges in this field and the future directions for development are proposed, with the aim of providing a valuable reference for achieving highly effective treatment of OPW.

A Novel Ensemble Machine Learning Model for Oil Production Prediction with Two-Stage Data Preprocessing

Petroleum production forecasting involves the anticipation of fluid production from wells based on historical data. Compared to traditional empirical, statistical, or reservoir simulation-based models, machine learning techniques leverage inherent relationships among historical dynamic data to predict future production. These methods are characterized by readily available parameters, fast computational speeds, high precision, and time–cost advantages, making them widely applicable in oilfield production. In this study, time series forecast models utilizing robust and efficient machine learning techniques are formulated for the prediction of production. We have fused the two-stage data preprocessing methods and the attention mechanism into the temporal convolutional network-gated recurrent unit (TCN-GRU) model. Firstly, the random forest (RF) algorithm is employed to extract key dynamic production features that influence output, serving to reduce data dimensionality and mitigate overfitting. Next, the mode decomposition algorithm, complete ensemble empirical mode decomposition with adaptive noise (CEEMDAN), is introduced. It employs a decomposition–reconstruction approach to segment production data into high-frequency noise components, low-frequency regular components and trend components. These segments are then individually subjected to prediction tasks, facilitating the model’s ability to capture more accurate intrinsic relationships among the data. Finally, the TCN-GRU-MA model, which integrates a multi-head attention (MA) mechanism, is utilized for production forecasting. In this model, the TCN module is employed to capture temporal data features, while the attention mechanism assigns varying weights to highlight the most critical influencing factors. The experimental results indicate that the proposed model achieves outstanding predictive performance. Compared to the best-performing comparative model, it exhibits a reduction in RMSE by 3%, MAE by 1.6%, MAPE by 12.7%, and an increase in R2 by 2.6% in Case 1. Similarly, in Case 2, there is a 7.7% decrease in RMSE, 7.7% in MAE, 11.6% in MAPE, and a 4.7% improvement in R2.

Research on the Soft-Sensing Method of Indicator Diagram of Beam Pumping Unit.

An accurate calculation of the indicator diagram of a pumping unit is the key factor in analyzing the performance of an oilfield production and operation and in preparing and optimizing an oilfield development plan. Aiming at the problems of the poor stability of the conventional load-displacement sensor method and the wave equation method, owing to the influence of an alternating load on the force sensor and the difficulty in measuring the crank angle using the electrical parameter method, a new soft sensing method employing the input electrical parameters of the motor and the beam inclination has been proposed to obtain the indicator diagram. At first, this method is established based on the beam angle of the pumping unit, which is easily measured using the suspension point displacement mathematics calculation model and the torque factor. Subsequently, the electric motor input parameters, the parameters of the four-bar linkage, and the relationship between the polished rod load have been established. Finally, the motor and the beam angle of the measured electrical parameters have been substituted into the calculation of the suspension point displacement and load value and pull in accordance with the guidelines to eliminate the singularity mutation values. After processing the measured data through a Butterworth filter, the indicator diagram is obtained. The results of the engineering experiment and application show that the average relative error of the method is less than 3.95%, and the maximum relative error remains within 2% for 6 months, which verifies the stability of the soft sensing method.

Production forecasting methods for different types of gas reservoirs

Hydrocarbon production in oil and gas fields generally progresses through stages of production ramp-up, plateau (peak), and decline during field development, with the whole process primarily modeled and forecasted using lifecycle models. SINOPEC's conventional gas reservoirs are dominated by carbonates, low-permeability tight sandstone, condensate, volcanic rocks, and medium-to-high-permeability sandstone. This study identifies the optimal production forecasting models by comparing the fitting coefficients of different models and calculating the relative errors in technically recoverable reserves. To improve forecast precision, it suggests substituting exponential smoothing method-derived predictions for anomalous data caused by subjective influences like market dynamics and maintenance activities. The preferred models for carbonate gas reservoir production forecasts are the generalized Weng's, Beta, Class-I generalized mathematical, and Hu-Chen models. The Vapor pressure and Beta models are optimal for forecasting the annual productivity of wells (APW) from gas-bearing low-permeability tight sandstone reservoirs. The Wang-Li, Beta, and Yu QT tb models are apt for moderate-to-small-reserves, single low-permeability tight sandstone gas reservoirs. The Rayleigh, Hu-Chen, and generalized Weng's models are suitable for condensate gas reservoirs. For medium-to-high-permeability sandstone gas reservoirs, the lognormal, generalized gamma, and Beta models are recommended.

Experimental Study on the Characterization of Aging Resistance Properties of Optical Cables in the Hydrogen-Containing Downhole Environment.

The utilization of downhole optical cables has significantly enhanced the efficiency and reliability of oilfield production operations; however, the challenging high-temperature and high-pressure conditions prevalent in oil-gas fields markedly reduce the service lifespan of these optical cables. This limitation severely impedes their application and further development in subterranean environments. In this study, a qualitative analysis was conducted on the structural materials utilized in two types of optical cables to identify these materials and assess the high-temperature tolerance and aging resistance properties of the optical fibers incorporated within. It was discovered that hydrogen infiltration into the subterranean optical cables predominantly accounts for their operational failure. To address this issue, an optical loss testing platform was established, facilitating the execution of a high-temperature and high-pressure hydrogen permeation aging experiment on the optical fibers, allowing for the evaluation of the hydrogen resistance capabilities of the two types of optical fibers. The findings from this study provide a theoretical foundation and methodological guidance for the optimization of optical fibers, aiming to enhance their durability and functional performance in adverse environmental conditions encountered in oil-gas field applications.

Oilfield analogy and productivity prediction based on machine learning: Field cases in PL oilfield, China

In the early time of oilfield development, insufficient production data and unclear understanding of oil production presented a challenge to reservoir engineers in devising effective development plans. To address this challenge, this study proposes a method using data mining technology to search for similar oil fields and predict well productivity. A query system of 135 analogy parameters is established based on geological and reservoir engineering research, and the weight values of these parameters are calculated using a data algorithm to establish an analogy system. The fuzzy matter-element algorithm is then used to calculate the similarity between oil fields, with fields having similarity greater than 70% identified as similar oil fields. Using similar oil fields as sample data, 8 important factors affecting well productivity are identified using the Pearson coefficient and mean decrease impurity (MDI) method. To establish productivity prediction models, linear regression (LR), random forest regression (RF), support vector regression (SVR), backpropagation (BP), extreme gradient boosting (XGBoost), and light gradient boosting machine (LightGBM) algorithms are used. Their performance is evaluated using the coefficient of determination (R2), explained variance score (EV), mean squared error (MSE), and mean absolute error (MAE) metrics. The LightGBM model is selected to predict the productivity of 30 wells in the PL field with an average error of only 6.31%, which significantly improves the accuracy of the productivity prediction and meets the application requirements in the field. Finally, a software platform integrating data query, oil field analogy, productivity prediction, and knowledge base is established to identify patterns in massive reservoir development data and provide valuable technical references for new reservoir development.

Reliability of permanent downhole systems: Minimum sample and quality index

Permanent downhole monitoring systems are responsible for measuring pressure and temperature time series and enable uninterrupted reservoir characterization during the oil field production period, playing a key role in the oil and gas industry. Located in hostile pressure and temperature environments (i) close to the reservoir, in the case of the PDG (Permanent Downhole Gauge) sensor, and (ii) at the wellhead, in the case of the TPT (Pressure and Temperature Transducer) and PT (Pressure Transducer), its data are transmitted from the subsea environment to the Floating Production Storage and Offloading (FPSO), where the Master Control System (MCS) provides the information in engineering format. This information fulfills its function in the FPSO plant and finally is stored in an onshore data historian. Such complexity, importance, and maintenance difficulty of this system make it necessary to control and manage its reliability. Therefore, the objective of this work is to increase the availability and maximize the useful life of the downhole permanent monitoring system through the reliability calculation, using the Weibull estimate with 2 parameters, and the application of an index quality of statistical inferences. The proposed method for estimating reliability uses a database containing information from permanent downhole monitoring systems of the PDG, TPT, and PT type, from January 1st, 2008 to January 9th, 2014, and considers only the failures that occur until the arrival of the data in the MCS. From the reliability results, it can be observed that stratifications of this database could generate samples with a smaller number of observations, thus inferring reliability even with a small number of samples. The deepening of this method results in the definition of the minimum sample that allows removing reliability inferences without statistical significance and a quality index that allows classifying the reliability estimates of stratified sets of the largest sample of a database. It is worth mentioning here that both methodologies developed in this work are inserted in a well monitoring system that intends to contribute to increasing the availability of pressure and temperature data for the management of well operations.

Maritime boundaries in the energy transition: carbon dioxide (CO2) storage across maritime jurisdictions

Governments around the world are looking to ensure their transition to full low-carbon economies whilst tackling climate change by implementing offshore carbon capture and storage (CCS) – a method of permanently removing carbon dioxide (CO2) from the burning of fossil fuels and burying it deep below the seabed in suitable geological formations. Among the main targets of such geological formations are depleted, or nearly depleted, offshore oil and gas reservoirs within existing oil-producing fields. However, such reservoirs will frequently transcend maritime boundaries and jurisdictions, ie a shared geological formation could be used on both sides of the maritime boundary for CO2 sequestration and storage. This raises the potential for disputes among nations, transboundary environmental degradation, and business disruption. The paper discusses the role of CCS in the low-carbon energy transition, focusing specifically on international legal aspects related to the storage of CO2 in sub-seabed geological formations of the continental shelf. Ongoing CO2 storage projects are examined to showcase critical technical aspects, including reservoir selection, well design, and post-injection monitoring. The analysis highlights the need for international coordination in situations where CO2 storage occurs across an international boundary and the importance of consent from all states with jurisdiction over the relevant CO2 storage formations. The paper concludes that existing maritime boundary agreements, including those with straddling deposit clauses, are unlikely to cover transboundary CO2 storage operations, except if they are considered incidental to ongoing petroleum operations.

Advancing PetroChina’s Development Strategies for Low-Permeability Oil Reservoirs

Based on PetroChina’s status and situation of low-permeability oil reservoir development, this paper analyzes the key common issues in the production capacity construction of new oilfields, the stable production of old oilfields, and enhanced oil recovery, and, in connection with the progress made in major development technologies and the results of major development tests for low-permeability oil reservoirs in recent years, puts forward the technical countermeasures and development directions. For optimizing the development of low-grade reserves, a comprehensive life-cycle development plan is essential, alongside experimenting with gas injection and energy supplementation in new fields. Addressing challenges in reservoir classification, multidisciplinary sweet spot prediction, and displacement–imbibition processes can significantly boost well productivity. In fine water flooding reservoirs, the focus should shift to resolving key technological challenges like dynamic heterogeneity characterization, and functional and nano-intelligent water flooding. For EOR, accelerating the application of carbon capture, utilization, and storage (CCUS) advancements, along with air injection thermal miscible flooding, and middle-phase microemulsion flooding, is crucial. This approach aims to substantially enhance recovery and establish a new model of integrated secondary and tertiary recovery methods.

Preparation, characterization, and evaluation of a nanomaterial reinforced particle gel system for the control of excessive water production in the mature oil fields

The use of a preformed particle gel system has become an attractive option for water shutoff jobs and conformance control in oil fields. Preformed particle gels (PPGs) have several advantages over conventional chemical techniques of water shutoff treatments. This current research work talks about the effect of the reinforcement of two nanomaterials i.e., bentonite nanoclay and silica nanomaterial in the polymer matrix of NRPG (Nanomaterial-Reinforced Particle Gel). Nanomaterials were added and act as physical crosslinkers that enhance the thermal and mechanical properties of the developed gel. The nanomaterial's surface area will create an “interaction zone” when it is dispersed in the polymer matrix, altering the polymer's behaviour, morphology, space charge distribution, and bond dispersion. The NRPG is developed using Acrylamide (AM), Vinyl pyrrolidone (VP), and 2-acrylamido-2-methylpropane sulfonic acid (AMPS) as a monomer, N, N-methylene bis acrylamide (NMBA) as a cross-linker. The equal concentration of two nanomaterials, bentonite nano clay and silica nanomaterial is used as a reinforcing agent via a free radical polymerization mechanism. Chemical characterizations such as Fourier Transform-Infrared Spectra (FT-IR), Powder X-ray Diffraction (P-XRD), Field Emission Scanning Electron Microscope (FESEM), Energy-dispersive X-ray spectroscopy (EDX), and Thermogravimetric Analysis (TGA) has carried out. In the current research work, tests were carried out to determine the effects of salinity, pH, multivalent ions, temperature, and nanomaterial concentrations, on the swelling of the NRPG. According to the findings, the NRPG swelling ratio decreased as salinity, pH, and nanomaterial concentration were increased. Moreover, there was a substantial increase in the swelling ratio at higher temperatures. Ampule sealing test has shown long-term thermal stability for more than 390 days at 120 °C. Rheological tests were performed to determine the mechanical strength of NRPG. In addition, the sandpack flooding experiment evaluates the plugging capacity of the NRPG to sandpack. These test results revealed that the plugging capacity of 0.5 wt % and 1 wt % suspension of NRPG is 96.03 % and 97.61 % and the residual resistance factor reaches 25.20 and 41.98 respectively. These findings suggest that the NRPG may be useful for water shutoff treatment in mature oilfields.

An investigation of the effect of drawdown pressure on sand production in an Iranian oilfield using a hybrid numerical modeling approach

AbstractReservoir pressure reduction due to continuous production from oil and gas wells affects the sand production rate. An increase in drawdown pressure and/or a decrease in reservoir pressure increases the sand production rate. Since the problem of sand production is one of the main issues in the Asmari sandstone formation located in one of the oilfields in the southwest of Iran, therefore, in this research, the variations in the sand production rate due to the changes in the reservoir and drawdown pressures were investigated. So, for the first time, a hybrid numerical model of finite difference method (FDM)—discrete element method (DEM)—finite element method (FEM)—computational fluid dynamics (CFD) was developed. This numerical model investigated the increase in the sand production rate due to variations in reservoir pressure with a constant bottom-hole flowing pressure. Then, by performing an extensive sensitivity analysis on different values of reservoir pressure and drawdown pressure, the changes in the sanding rate, the critical drawdown pressure, and the safe drawdown line were determined. The results showed that, if the production flow rate of the well is constant, increasing the drawdown pressure can change the sand production rate only to a certain extent, and more than that, will be produced at a constant rate. Also, adjusting the drawdown pressure within a safe range does not necessarily keep the sand production rate constant at a permissible value for a long time, while by keeping the bottom hole flowing pressure constant within an acceptable range, the sand production rate can be controlled for a longer period.

DETERMINATION OF HYDROCARBON ZONE AND DEPOSITIONAL ENVIRONMENT FACIES IN TALANG AKAR FORMATION, SOUTH SUMATRA BASIN AT "EPURA" FIELD

The EPURA field is one of the oil and gas producing fields in the South Sumatra Basin, where well completion has been carried out in the Talang Akar Formation, and the production test results are interpreted to mean that in wells EP-13, EP-14, EP-15, EP-16, EP-17 and EP-23 contain several reservoir zones that have the potential to contain hydrocarbons. This research with facies interpretation analysis uses data from six wells (wireline, mudlog, RCAL and lithology data), so it is hoped that it can provide more detailed information for the development of an oil and gas field. The analysis carried out is in the form of facies analysis, depositional environment, electrofacies and facies correlation. From the research results, it was found that the Talang Akar Formation has depositional facies in the form of a fluvial, which in this study is the Lower Talang Akar Formation with depositional facies in the form of channel, Crevasse Splay, point bar and flood plain. Based on the analysis results, the Talang Akar Formation is divided into 3 reservoir zones, namely Zone EP-1, EP-2, and EP-3. After going through all stages of petrophysical analysis, it was found that zones with high hydrocarbon potential were found in wells EP-13, EP-23 and EP-16. The wells with low hydrocarbon potential are EP-14, EP-15 and EP-17 wells. The zone of highest hydrocarbon potential in prospect wells is in the EP-1 zone with a Crevasse Splay facies association and has thick sandstone lithology characteristics with medium to fine grain size.

Research and Application of the Fourth Generation Stratified Water Injection Technology in Daqing Oilfield

Stratified water injection is the most important characteristic technology in Daqing oilfield development, providing technical support for efficient oilfield development. With the oilfield entering the ultra-high water cut stage, the remaining oil is highly dispersed, the oil-water relationship is complex, the qualified rate of water injection decreases rapidly, and the difficulty of stabilizing oil and controlling water is increasing. In order to solve the contradiction between the increasing workload of water injection well testing and the limited testing team, and mee t the needs of oilfield precision development, the cable-controlled layered water injection technology has been developed. In this technology, the pressure monitoring system, flow monitoring system and flow control system are placed in the preset cable intelligent water distributor. At the office end, the technicians send control instructions on the server software, and send them to the ground control box through the oilfield production wireless network. The cable carrier technology is used to transmit the instructions to the intelligent water distributor through the cable, so as to achieve real-time communication, obtain the downhole layering parameter information, and control the downhole layering injection volume. Ten intelligent injection technology demonstration areas have been built to verify the process adaptability under different development contradictions. The cable-controlled layered water injection technology improves the proportion of water absorption thickness, effectively controls the water cut rise rate and natural decline rate, and has obvious oil increase effect, promoting the digital transformation and intelligent development of the oilfield.

Particle distribution and two-phase flow characteristics of twin-screw pump during solid-liquid transfer

The twin-screw pump is a kind of positive displacement machinery with smooth pressure and flow pulsation and strong self-priming ability, which is widely used in the fields of oilfield production, marine engineering, and other fields. However, in the process of conveying liquid-phase media, it is difficult to avoid the inclusion of solid impurities and grit, resulting in wear of the pump casing and rotor, and the pump’s pressurization capacity is reduced or even shut down. At present, the solid-liquid two-phase flow characteristics within the twin-screw pump have not been clarified, which hinders the study of particle wear in the pump. In this paper, a solid-liquid two-phase flow study is carried out on a twin-screw pump through numerical simulation and experimental testing. The distribution of particles with different diameters in the rotor domain with the liquid-phase transport process is explored by simulating the two-phase flow under different differential pressures and particle concentrations. The results show that the particles in the rotor domain are mainly distributed in the region away from the male and female rotor engagement, and the number of particles near the engagement is small but the velocity is higher under the influence of the clearance jets; the elevation of the differential pressure and the particle concentration increase the risk of the particles to collide with the rotor more frequently and at higher velocity; at different particle concentrations, new localized vortices are caused by particle conveying which compared to pure liquid transport, but there are also cases where the original vortices are suppressed. The results will provide a theoretical basis for further research on particle wear characteristics in twin-screw pumps.

Unlocking the hydrocarbon potential: Formation evaluation and petrophysical properties of the upper Triassic Kurra Chine Formation in Sarta Oil Field, Kurdistan Region, Northern Iraq

The Upper Triassic Kurra Chine Formation in the Sarta oil field of the Kurdistan Region of Northern Iraq has garnered limited attention, notwithstanding the keen interest of numerous international oil companies in drilling wells within this geological epoch. This study endeavors to thoroughly investigate the Formation Evaluation and petrophysical properties of the Kurra Chine Formation in the production oil field, with a specific focus on Sarta Well-2 (S-2). The research incorporates diverse methods for formation evaluation and analysis of petrophysical properties, employing conventional wireline logs such as Gamm-Ray, Neutron, Density, Sonic, Resistivity, Caliper, and Bit size.The research findings reveal that the thickness of the Kurra Chine Formation in S-2 is approximately 380 m. The pay zones of S-2 exhibit an average shale volume of 17 %. The dominant lithology in S-2 comprises Limestone, Dolomite, Anhydrite, Shale, and Sandstone. The average total porosity within the pay zones is determined to be 6 % in S-2. Furthermore, the average effective porosity in reservoir zones of the S-2 is estimated to be 5 %, while the average secondary porosity in these zones is found to be 6 % in S-2. The average permeability in the pay zones of the Sarta well is reported to be 30.6 millidarcy (mD). Additionally, the average water saturation in the pay zones is determined to be 35 % in S-2, whereas the average hydrocarbon saturation is estimated to be 45 % in S-2.This study furnishes comprehensive descriptions and analyses of the formation evaluation and petrophysical properties of the Kurra Chine Formation in Northern Iraq, shedding light on the characteristics and potential of this oil-bearing formation.

Chemical Risk Assessment and Prevention Action Plan Related to Petroleum Production. Case Study of Laboratory and Storage Units in an Algerian Oil and Gas Company

Chemical risk is considered one of the most frequent risks in the workplace, affecting the safety of workers continuously exposed to chemical substances. In addition, it can have an environmental impact and cause an explosion when unacceptable conditions are met. To know the effects of chemical risks and how to prevent them, this study is proposed, the main objective of which is the evaluation of chemical hazards and the proposal of an action plan to avoid this kind of risk in industrial companies. Our case study focused on the crude oil production company " PERTAMINA" using the SEIRICH software. The results indicate that most chemicals are hazardous and can cause serious harm to workers exposed to them periodically. Therefore, the proposed preventive action plan for safety improvement aims to ensure continuous development in oil and gas field production, processing, and distribution, taking into account the health and safety of workers.

Assessment of hydrogen storage capacity in porous media at the European scale

A first assessment of the storage resource at European scale for underground hydrogen storage in porous media is presented for the European Union and some neighboring countries (Norway, Türkiye, Ukraine, United Kingdom). The study includes different types of porous media: existing underground gas storages, depleted oil and gas fields, deep saline formations. The storage resources are computed based upon a volumetric analytical approach which accounts for hydrogen physical characteristics (density, viscosity, sweep efficiency and capillary trapping). The computed storage resource is in good agreement with published dynamic storage capacity of deep saline formations in Poland.The extension to the continental scale enables a consistent estimate of the various storage resources. The working storage resources at the European scale are about 8000 TWh among which 37 % are onshore which covers the expected storage requirements. The agreement with previously published working storage capacities for depleted gas fields in the UK continental shelf is quite good at about 2662 TWh. However, at the field level, there might be significant differences linked with the consistency requirements at European scale of this study which estimates the production of oil and gas fields without using the actual field production.Despite its restriction of publicly available data, these results show significant storage resources. The working capacities are not evenly distributed over the continent. However, assuming no competitive usage, the working storage resource would be extremely significant when accounting for onshore and offshore potential. Amongst the different porous media, the underground gas storages present the most interest for conversion to hydrogen underground storage despite their smaller storage resource, 460 TWh, than for depleted gas fields, 5440 TWh for the onshore and offshore. The estimate of working storage resource in deep saline formation is quite low, only 46 TWh as it relies upon traps that were previously characterized.

Organic geochemical heterogeneity of cretaceous mudrocks and reassessment of oil sources in the Tano Basin, Ghana

The Tano Basin in Ghana, situated within the South Atlantic margin, is a significant area for petroleum exploration. Previous studies have recognized the presence of source rocks rich in organic matter from the Cretaceous period in this basin. However, the specific origins of this organic matter, as well as the thermal maturity and depositional environment of the Cretaceous source strata, are not well characterized in existing literature. Here, geochemical data are reported on the bulk geochemical composition of 45 Maastrichtian to Albian-aged rock cuttings via pyrolysis and total organic carbon (TOC) analysis. Out of these samples, 29 were selected for further biomarker and stable carbon isotope (δ13C) analysis. The biomarker and isotopic signatures of the 29 rock extracts and 6 crude oils from the basin's productive Jubilee and TEN oil fields were compared to establish oil-oil and oil-source correlations. The Cenomanian and Turonian source rocks showed the greatest oil generation potential based on current bulk geochemical analysis. These rocks are dominated by oil-prone organic matter and are at a more favorable maturity stage compared to the Maastrichtian, Santonian, and Coniacian (M-S-C) rock suites. In contrast, the Albian rock samples, characterized by mixed Type II/III and Type III kerogen, and their high thermal maturity, indicate a high potential for the generation of gaseous hydrocarbons. The biomarker and isotope data from the Cenomanian, Turonian, and Albian (T-C-A) source rocks suggest that they were deposited in a Transitional Marine-Lacustrine environment characterized by reducing redox conditions. This environment effectively preserved organic matter from diverse sources such as bacteria, algae, and higher plants. Furthermore, biomarker ratios indicated that the T-C-A source rocks are in the early-peak mature window. On the other hand, the M-S-C source rocks appear to have been deposited under suboxic conditions in a Coastal Marine environment. Lower aquatic organisms dominate these rocks, which have an immature to marginally mature level. The analysis of lower molecular weight hydrocarbons (≤C20), characterized by an unresolved complex mixture, did not reveal any obvious correlation between the oils and the Cretaceous source rocks. However, the analysis of higher molecular weight hydrocarbons (≥C20) and isotopic ratios indicated that the commercial discoveries in the Jubilee and TEN fields share a genetic similarity and are primarily sourced from the T-C-A source rocks. Furthermore, the molecular and isotopic characteristics suggest that the M-S-C source rocks do not appear to have contributed to the oils found in the Jubilee and TEN fields. These new geochemical findings shed light on the paleoenvironmental conditions and source rock characteristics of the region, significantly contributing to our understanding of the petroleum evolution and potential of the Tano Basin.

Features selection for recognition of severe slugging in a long pipeline with an S-shaped riser by decision tree

In deep-sea oil and gas, S-shaped riser is the key equipment to transport the multiphase working substance produced underwater to the surface platform. The occurrence of severe slugging will seriously threaten the safe production of offshore oil and gas fields. Therefore, accurate and rapid recognition of hazardous flow patterns such as severe slugging is an urgent need to ensure the safety of multiphase flow in deep-sea long-distance pipelines. This paper has built a set of long S-shaped riser with industrial parameters, including 1687 m horizontal and downward inclined pipelines and 16.7 m S-shaped riser. The gas-liquid two-phase flow patterns, including severe slugging, oscillating flow and stable flow, are studied in this system. The pressure and differential pressure features of different signals are extracted from different positions along the pipeline, and a more comprehensive and reasonable evaluation criterion of signal performance is established. Making use of the advantages of visualization of the structure of decision tree, a new method to evaluate the recognition effect of features is proposed based on its classification principle. The original signal is decomposed into components of different scales through wavelet multi-scale analysis, and then the statistical features with good flow pattern differentiation ability are calculated. It is found that the mean of wavelet approximate component has the best recognition effect among all features. On the basis of feature correlation analysis, 7 features with high recognition rate applicable to 22 signals along the pipeline are optimally selected from 13 original features. For the water differential pressure signal DP13, the recognition rate obtained by using its 4 optimal features is 91.4 %, and the error between the recognition rate obtained by using all features is only 0.2 %. The overall recognition rate of the signal is the highest and the practicability is the best. When the sample duration is 6.2s, the recognition rate using the optimal feature reaches 90.8 %, thus ensuring the real-time recognition of the flow pattern while obtaining a high recognition rate.

Research on hot water chemical flooding technology in Bohai heavy oil field

Introduction: The hot water chemical flooding technology effectively improves the fluidity ratio and enhances the horizontal and vertical oil displacement efficiency of the reservoir through the synergistic effect of thermal energy and chemicals, which can further enhance the recovery rate on the basis of throughput thermal recovery.Methods: Based on the geological reservoir parameters of Bohai B oilfield, an oil recovery system evaluation experiment and scheme design study were carried out. Injection parameters such as hot water temperature, chemical agent concentration, and chemical agent dosage that affect the oil recovery effect of hot water chemical flooding were optimized and designed. The development characteristics and effects of two thermal recovery technologies, namely multi thermal fluid throughput and hot water chemical flooding, were compared and analyzed.Results: The results show that with the increase of temperature, the effect of chemical agents on improving the water-oil mobility ratio and reducing the viscosity of crude oil is weakened, and the thermal energy plays a leading role in enhancing oil recovery, but when the temperature is higher than 115°C, the improvement of oil recovery is slowed down, and the comprehensive economic indicators decline rapidly. As the concentration of chemical agent increases, the enhanced oil recovery increases monotonously. When the concentration is 1500 mg/L, the comprehensive economic indicators reach the peak and then decline, indicating that the efficiency of chemical agent decreases. The total amount of chemical agent shall be controlled within 0.25 ~ 0.30 PV. The case calculation shows that hot water chemical flooding can expand the effective radius from 80 m to 400 m, more effectively use the reserves between injection and production wells, increase the oil recovery by 4.8 percentage points, and increase the oil yield by 31.7 m3/t per ton of agent.Discussion: It is suggested that Bohai B Oilfield can adopt hot water chemical flooding after the multiple thermal fluid huff and puff to continuously guarantee the oilfield production.