Showing papers in "Journal of Petroleum Exploration and Production Technology in 2020"

The effect of surfactant concentration, salinity, temperature, and pH on surfactant adsorption for chemical enhanced oil recovery: a review

Abstract: Enhanced oil recovery (EOR) processes have a great potential to maximize oil recovery factor of the existing reservoirs, where a significant volume of the unrecovered oil after conventional methods is targeted. Application of chemical EOR techniques includes the process of injecting different types of chemicals into a reservoir to improve the overall sweep efficiency. Surfactant flooding is one of the chemical EOR used to reduce the oil–water interfacial tension and to mobilize residual oil toward producing wells. Throughout the process of surfactant flooding, selecting a suitable surfactant for the reservoir conditions is quite challenging. Surfactants tend to be the major factor associated with the cost of an EOR process, and losing surfactants leads to substantial economic losses. This process could encounter a significant loss of surfactant due to adsorption into the porous media. Surfactant concentration, salinity, temperature, and pH were found to be as the main factors that influence the surfactant adsorption on reservoir rocks. Most of the research has been conducted in low-temperature and low-salinity conditions. Only limited studies were conducted in high-temperature and high-salinity (HT/HS) conditions due to the challenging for implementation of surfactant flooding in these conditions. This paper, therefore, focuses on the reviews of the studies conducted on surfactant adsorption for different surfactant types on different reservoir rocks under different reservoir conditions, and the influence of surfactant concentration, salinity, temperature, and pH on surfactant adsorption.

Carbonate reservoir characterization: an integrated approach

Abstract: Estimation of fluid and rock properties of a hydrocarbon reservoir is always a challenging matter; especially, it is true for heterogeneous carbonate reservoirs. Petrophysical logs and laboratory activities are common methods for characterizing a hydrocarbon reservoir. This method in conjunction with geostatistical methods is applied to relatively homogeneous sandstone reservoirs or matrix media of dual-porosity heterogeneous carbonate reservoirs. To estimate properties of fracture system of a dual-media carbonate reservoir, outcrop properties, electrical borehole scans, fractal discrete fracture network and analogy with other reservoirs are common methods. Results which obtained from these methods describe the reservoir in a static way and could be relied on them for very small portion of the reservoir. In this paper, a dynamic procedure for describing reservoir features is proposed in order to enhance the conventional reservoir characterization methods. This method utilizes the reported production data for a specific period of time in conjunction with rock and fluid properties to estimate drainage radius of the well and matrix block height, porosity and width of fracture in the estimated drainage radius. The presented method is elaborated through its application in a real case. By this method, one can generate maps of matrix block size and fracture width and porosity throughout the reservoir. Also, it could be a powerful tool for estimation of effectiveness of acid/hydraulic fracturing activity.

Critical review of asphaltene properties and factors impacting its stability in crude oil

Abstract: Asphaltene is a component of crude oil that has been reported to cause severe problems during production and transportation of the oil from the reservoir. It is a solid component of the oil that has different structures and molecular makeup which makes it one of the most complex components of the oil. This research provides a detailed review of asphaltene properties, characteristics, and previous studies to construct a guideline to asphaltene and its impact on oil recovery. The research begins with an explanation of the main components of crude oil and their relation to asphaltene. The method by which asphaltene is quantified in the crude oil is then explained. Due to its different structures, asphaltene has been modeled using different models all of which are then discussed. All chemical analysis methods that have been used to characterize and study asphaltene are then mentioned and the most commonly used method is shown. Asphaltene will pass through several phases in the reservoir beginning from its stability phase up to its deposition in the pores, wellbore, and facilities. All these phases are explained, and the reason they may occur is mentioned. Following this, the methods by which asphaltene can damage oil recovery are presented. Asphaltene rheology and flow mechanism in the reservoir are then explained in detail including asphaltene onset pressure determination and significance and the use of micro- and nanofluidics to model asphaltene. Finally, the mathematical models, previous laboratory, and oilfield studies conducted to evaluate asphaltene are discussed. This research will help increase the understanding of asphaltene and provide a guideline to properly study and model asphaltene in future studies.

A critical review of development and demulsification mechanisms of crude oil emulsion in the petroleum industry

Abstract: The need for efficient demulsification process to treat emulsions in the petroleum industry is well acknowledged. For decades, numerous researches have been conducted to examine mechanisms of emulsification and demulsification. Untreated emulsion has both technical and commercial implications in the industry, especially in terms of treatment facilities, refining and transportation. Effective treatment is needed to ensure optimum production of hydrocarbons. The present paper is to review reported works on the formation of petroleum emulsions, demulsification treatments, characteristics of fit-for-purpose demulsifiers as well as research trends in emulsion treatment. Crude oils are naturally combined with natural surfactants having high tendency to form stable emulsion. The stable emulsion must be treated well to meet industrial requirements since crudes with a high volume of stable emulsion have a less value. Therefore, fundamental studies on natural surfactants, which contribute to the emulsion stability, are analyzed for the effective separation of emulsions into oil and water. This would involve the assessment of various reported mechanisms for the emulsification and right formulation for effective demulsification.

A comprehensive review of nanoparticles applications in the oil and gas industry

Abstract: With the increased attention toward nanotechnology and their innovative use for different industries including but not limited to food, biomedical, electronics, materials, etc, the application of nanotechnology or nanoparticles in the oil and gas industry is a subject undergoing intense study by major oil companies, which is reflected through the huge amount of funds invested on the research and development, with respect to the nanotechnology. Nanotechnology has been recently investigated extensively for different applications in the oil and gas industry such as drilling fluids and enhanced oil recovery in addition to other applications including cementing and well stimulation. In this paper, comprehensive literature was conducted to review the different applications of nanotechnology in the oil and gas industry. A summary of all nanoparticles used along with a detailed analysis of their performance in improving the targeted parameters is comprehensively presented. The main objective of this review was to provide a comprehensive summary of the different successful applications of nanotechnology and its associated challenges, which could be very helpful for future researches and applications.

An investigation on the effects of silica and copper oxide nanoparticles on rheological and fluid loss property of drilling fluids

Abstract: The increase in hydrocarbon production from problematic production zones having high fluid loss and formation damage has led to the emergence of non-damaging drilling fluids (NDDF). Recently, nanotechnology has found a wide array of applications in the oil and gas industry. Most applications of nanotechnology and enhancement in properties of drilling fluids are restricted to bentonite, xanthan gum and a few oil-based mud. In this study, the effects of silica and copper oxide nanoparticles on polyamine-based NDDF and conventional bentonite-based drilling fluids (BDF) were investigated. Silica nanoparticles were prepared using sol–gel method, and copper oxide nanoparticles were synthesized using co-precipitation method. Nano-based drilling fluids were prepared by dispersing nanoparticles in concentrations of 0.5%, 0.8% and 1% by weight. Furthermore, testing of these nano-based drilling fluids was conducted by measuring specific gravity, pH, rheological properties and filtrate loss at surface temperature (room temperature) and then aging it at bottom-hole temperature (80 °C). The addition of silica and copper oxide nanoparticles to both the drilling fluids did not show much effect on pH and specific gravity. Addition of 0.5% concentration of silica nanoparticles in NDDF showed least degradation in rheological properties compared to other fluids. It showed reduction in filtrate loss by 31%. Moreover, silica nanoparticles in conjunction with BDF acted as a mud thinner showing a decrease in viscosity and yield point. On the contrary, when used with NDDFs, silica nanoparticles acted as a mud thickener. Copper oxide nanoparticles behaved as a thinner in both the drilling fluids with a highest reduction in plastic viscosity of 24% for 0.8% of copper oxide nanoparticle in BDF. Thinning properties were enhanced as the doping concentrations of copper oxide nanoparticles increased; however, the fluid loss controlling ability decreased except for 0.5% concentration by 31% and 24% when used with both the drilling fluids. Additionally, optimal Herschel–Bulkley parameters have been determined by using genetic algorithm to minimize the function of sum of squared errors between observed values and model equation.

Interaction between hydraulic fractures and natural fractures: current status and prospective directions

Abstract: Hydraulic fracturing treatment is one of the most efficient conventional matrix stimulation techniques currently utilized in the petroleum industry. However, due to the spatiotemporal complex nature of fracture propagation in a naturally- and often times systematically fractured media, the influence of natural fractures (NF) and in situ stresses on hydraulic fracture (HF) initiation and propagation within a reservoir during the hydrofracturing process remains an important issue. Over the past 50 years of advances in the understanding of HF–NF interactions, no comprehensive revision of the state of the knowledge exists. Here, we reviewed over 140 scientific articles on investigations of HF–NF interactions, published over the past 50 years. We highlight the most commonly observed HF–NF interactions and their implications for unconventional oil and gas production. Using observational and quantitative analyses, we find that numerical modeling and simulation is the most prominent method of approach, whereas there are less publications on the experimental approach, and analytical method is the least utilized approach. Further, we suggest how HF–NF interactions can be monitored in real time on the field during a pre-frac test. Lastly, based on the results of our literature review, we recommend promising areas of investigation that may provide more profound insights into HF–NF interactions in such a way that can be directly applied to the optimization of fracture-stimulation field operations.

Evaluation of new surfactants for enhanced oil recovery applications in high-temperature reservoirs

Abstract: Surfactants have been successfully used for enhanced or improved oil recovery in reservoirs having mild conditions (low temperature, low salinity). Reservoirs having harsh conditions, however, offer unique challenges in that most surfactants precipitate and chemically degrade due to a combined effect of high temperature and hardness salinity. Industry’s efforts are continuing to develop or formulate surfactants for oil recovery applications to high temperature and salinity. The aim of this study was to evaluate several modified anionic surfactants/formulations that were claimed to be able to overcome the unfavorably high-salinity brine (sea water) and high temperature and to understand the impact of high temperature to surfactant adsorption. A series of experiments were conducted to characterize and quantify the effects of aging time in high temperature (106 °C) and seawater salinity (32,000 ppm with 1600 hardness) on surfactant performance. Results for both sulfate- and sulfonate-based surfactants were deemed not to be satisfactory. Sulfate-based surfactants encountered hydrolysis problem at high temperature, whereas sulfonate-based surfactants precipitated in the presence of divalent ions. This study then focused on alkyl ether carboxylate (AEC) as the main surfactant, and blends of AEC with alkyl polyglucoside (APG). To find the optimum conditions, phase behavior tests were performed with a fixed seawater salinity but with different blending ratios of surfactant and co-surfactant, as well as overall surfactant concentrations, similar to the salinity scan. Type III microemulsion was observed for both surfactant solutions of AEC and AEC–APG blend with IFT of 10−3 mN/m (millinewton/meter). Surfactant adsorption resulted in lower adsorption in the high-temperature region. The results of this project are urgently needed by the industry for future screening in order to find suitable surfactants for applying to reservoirs with harsh conditions. The study also intends to provide an understanding of adsorption relationship to high temperature, as a guideline in addressing surfactant losses due to adsorption at high-temperature field application.

Machine learning-based models for predicting permeability impairment due to scale deposition

Abstract: Water injection is one of the robust techniques to maintain the reservoir pressure and produce trapped oil from oil reservoirs and improve an oil recovery factor. However, incompatibility between injected water and reservoir water causes an unflavored issue named “scale deposition.” Owing to the deposited scales, effective permeability of a reservoir reduced, and pore throats might be plugged. To determine formation damage owing to scale deposition during a water injection process, two well-known machine learning methods, least squares support vector machine (LSSVM) and artificial neural network (ANN), are employed in the present paper. To improve the performance of the LSSVM method, a metaheuristic optimization algorithm, genetic algorithm (GA), is used. The constructed LSSVM model is examined using real formation damage data samples experimentally measured, which was reported in the literature. According to the obtained outputs of the above models, LSSVM has a high performance based on the correlation coefficient, and infinitesimal uncertainty based on a relative error between the model predictions and the corresponding actual data samples was less than 15%. Outcomes from this study indicate the useful application of the LSSVM approach in the prediction of permeability reduction due to scale deposition, and it can lead to a better and more reliable understanding of formation damage effects through water flooding without expensive laboratory measurements.

Experimental investigation of environmentally friendly drilling fluid additives (mandarin peels powder) to substitute the conventional chemicals used in water-based drilling fluid

Abstract: The non-biodegradable additives used in controlling drilling fluid properties cause harm to the environment and personal safety. Thus, there is a need for alternative drilling fluid additives to reduce the amount of non-biodegradable waste disposed to the environment. This work investigates the potential of using mandarin peels powder (MPP), a food waste product, as a new environmentally friendly drilling fluid additive. A complete set of tests were conducted to recognize the impact of MPP on the drilling fluid properties. The results of MPP were compared to low viscosity polyanionic cellulose (PAC-LV), commonly used chemical additive for the drilling fluid. The results showed that MPP reduced the alkalinity by 20–32% and modified the rheological properties (plastic viscosity, yield point, and gel strength) of the drilling fluid. The fluid loss decreased by 44–68% at concentrations of MPP as less as 1–4%, and filter cake was enhanced as well when comparing to the reference mud. In addition, MPP had a negligible to minor impact on mud weight, and this effect was resulted due to foaming issues. Other properties such as salinity, calcium content, and resistivity were negligibly affected by MPP. This makes MPP an effective material to be used as pH reducer, a viscosity modifier, and an excellent fluid loss agent. This work also provides a practical guide for minimizing the cost of the drilling fluid through economic, environmental, and safety considerations, by comparing MPP with PAC-LV.

Transforming petroleum downstream sector through big data: a holistic review

Abstract: Big data refers to store, manage, analyze, and process efficiently a huge amount of datasets and to distribute it. Recent advancements in big data technologies include data recording, storage, and processing, and now big data is used in the refinery sector for the estimation of the energy efficiency and to reduce the downtime, maintenance, and repair cost by using various models and analytics methods. In the liquefied natural gas and city gas distribution industry, also, it is used in maintenance and to predict the failure of process and equipment. In this paper, authors have reviewed that how big data now used in the storage and transportation of oil and gas, health and safety in the downstream industry and to accurately predict the future markets of oil and gas. There are many areas where we can efficiently utilize big data techniques, and there are several challenges faced in applying big data in the petroleum downstream industry.

Carbonated water injection: an efficient EOR approach. A review of fundamentals and prospects

Abstract: Carbonated water injection (CWI) might be an efficient alternate to CO2 injection technique. In CWI, CO2 exists as a dissolved phase and not as a free phase; thus, it eliminates some challenges encountered in CO2 injection such as poor sweep efficiency and gravity segregation. In CWI, the density and viscosity of water become higher than normal due to the CO2 dissolution, thereby reducing the gravity segregation and channeling effect. This article is a comprehensive review on how carbonated water flooding has evolved over the time and captured salient features on the mechanisms involved in its role in enhanced oil recovery. The aspects reviewed in this article include a brief comparison of conventional CO2 injection and carbonated water injection and the benefits thereof. Solubility of CO2 in water, brine and oil phases is discussed in detail with valid correlations. A brief history of the development of CWI in the laboratory and field information is captured from 1905s to the present followed by the possible mechanisms and principle of CWI reported by various authors. This article also captured the latest findings on the beneficial effect of hybridizing CWI with smart water technologies.

A comparative study of heterogeneous ensemble methods for the identification of geological lithofacies

Abstract: Mudstone reservoirs demand accurate information about subsurface lithofacies for field development and production. Normally, quantitative lithofacies modeling is performed using well logs data to identify subsurface lithofacies. Well logs data, recorded from these unconventional mudstone formations, are complex in nature. Therefore, identification of lithofacies, using conventional interpretation techniques, is a challenging task. Several data-driven machine learning models have been proposed in the literature to recognize mudstone lithofacies. Recently, heterogeneous ensemble methods (HEMs) have emerged as robust, more reliable and accurate intelligent techniques for solving pattern recognition problems. In this paper, two HEMs, namely voting and stacking, ensembles have been applied for the quantitative modeling of mudstone lithofacies using Kansas oil-field data. The prediction performance of HEMs is also compared with four state-of-the-art classifiers, namely support vector machine, multilayer perceptron, gradient boosting, and random forest. Moreover, the contribution of each well logs on the prediction performance of classifiers has been analyzed using the Relief algorithm. Further, validation curve and grid search techniques have also been applied to obtain valid search ranges and optimum values for HEM parameters. The comparison of the test results confirms the superiority of stacking ensemble over all the above-mentioned paradigms applied in the paper for lithofacies modeling. This research work is specially designed to evaluate worst- to best-case scenarios in lithofacies modeling. Prediction accuracy of individual facies has also been determined, and maximum overall prediction accuracy is obtained using stacking ensemble.

Enhancing the performance of xanthan gum in water-based mud systems using an environmentally friendly biopolymer

Abstract: Xanthan gum is commonly used in drilling fluids to provide viscosity, solid suspension, and fluid-loss control. However, it is sensitive to high temperatures and not tolerant of field contaminants. This paper presents an experimental study on the effects of an eco-friendly biopolymer (diutan gum) on xanthan gum (XC) in a water-based bentonite mud. Laboratory experiments were carried out for different compositions of the biopolymers in water-based bentonite muds formulated without salt and in water-based bentonite muds containing sodium chloride (NaCl). The rheological properties of the water-based bentonite muds formulated with XC (2 Ibm) and those of the water-based bentonite muds prepared using XC (1Ibm) and diutan gum (1Ibm) were measured using Model 1100 viscometer after aging at 25 °C, 100 °C, and 120 °C for 16 h. The API fluid loss and filter cake of the mud formulations were measured using HTHP filter press. The properties of the water-based bentonite muds containing only XC were compared with those of the water-based bentonite muds containing XC and diutan gum. Presented results show that combining diutan gum and xanthan gum in a ratio of 1:1 in a water-based bentonite mud enhances its performance with respect to fluid properties—apparent viscosity, gel strength, yield points, YP/PV ratio, LSRV, n, and K. The fluid formulations also showed favorable mud cake building characteristics. Experimental data also indicate a 16%, 19%, and 34% reduction in API fluid loss values for the water-based benitoite muds containing XC in the presence of diutan gum after aging at 25 °C, 100 °C, and 120 °C for 16 h, respectively. Experimental results also show that the water-based benitoite mud containing XC and diutan gum would cause less formation damage and was tolerant of contamination with a monovalent cation (Na+). The synergy of xanthan gum and diutan gum can, therefore, improve the performance of water-based drilling fluids.

The effect of drill–pipe rotation on improving hole cleaning using polypropylene beads in water-based mud at different hole angles

Abstract: Hole cleaning is always a problem, particularly during drilling operations, and drilling fluid plays an important role in transporting drill cuttings through an annular section of wellbore to the surface. To transport the cuttings, a water-based mud with added polypropylene beads was selected since it is environmentally friendly and cost efficient. The polypropylene beads help to transport cuttings by providing an additional buoyancy force that lifts the cuttings to the surface via the influence of collision and drag forces. This experiment was performed using a 20 ft test section, 10 ppg drilling mud and 0.86 m/s annular velocity in a laboratory scale rig simulator, and the concentration of polypropylene beads was varied from 0 to 8 ppb. As the concentration of polypropylene increases, the cutting transport ratio also increases. It was observed that the fewest cuttings are lifted at a critical angle of 60°, followed by 45°, 30°, 90° and 0°. Additionally, cutting sizes had moderate effects on the cutting lifting efficiency, where smaller cutting sizes (0.5–1.0 mm) are easier to lift than larger cutting sizes (2.0–2.8 mm). Furthermore, a study of buoyancy force and impulsive force was conducted to investigate the cutting lifting efficiencies of various concentrations of polypropylene beads. This lifting capacity was also assisted by the presence of polyanionic cellulose (PAC), which increases the mud carrying capacity and is effective for smaller cuttings. The results show that in the presence of pipe rotation, the cutting lifting efficiency is slightly enhanced due to the orbital motion provided by the drill pipe for better hole cleaning. In conclusion, polypropylene beads combined with pipe rotation increase the cutting transport ratio in the wellbore.

Response surface methodology-based optimization of biosurfactant production from isolated Bacillus aryabhattai strain ZDY2

Abstract: A potential biosurfactant producing isolate was identified as Bacillus aryabhattai strain ZDY2. Biosurfactant production was enhanced by 2.51-fold through the development of an optimized process using response surface methodology. The optimized culture medium contained crude oil 4.0%, yeast extract 0.7% and NaNO3 3.0% that yielded 8.86 g/l of biosurfactant. Biosurfactant was characterized for stability up to 100 °C, at pH 5–10 and in the presence of NaCl concentration up to 8%. Biosurfactant demonstrated antimicrobial activity against Salmonella typhimurium, Escherichia coli, Micrococcus luteus, Staphylococcus aureus and Candida tropicalis. The morphological characterization was carried out by scanning electron microscopy with energy-dispersive X-ray analysis. The Fourier-transform infrared spectroscopy analysis reveals the lipopeptide nature of the biosurfactant produced by B. aryabhattai strain ZDY2. The biosurfactant finds application in healthcare and pharmaceutical industries.

Reservoir quality evaluation of the Farewell sandstone by integrating sedimentological and well log analysis in the Kupe South Field, Taranaki Basin-New Zealand

Abstract: The study used the sedimentological and well log-based petrophysical analysis to evaluate the Farewell sandstone, the reservoir formation within the Kupe South Field. The sedimentological analysis was based on the data sets from Kupe South-1 to 5 wells, comprising the grain size, permeability, porosity, the total cement concentrations, and imprints of diagenetic processes on the reservoir formation. Moreover, well log analysis was carried on the four wells namely Kupe South 1, 2, 5 and 7 wells for evaluating the parameters e.g., shale volume, total and effective porosity, water wetness and hydrocarbon saturation, which influence the reservoir quality. The results from the sedimentological analysis demonstrated that the Farewell sandstone is compositionally varying from feldspathic arenite to lithic arenite. The analysis also showed the presence of significant total porosity and permeability fluctuating between 10.2 and 26.2% and 0.43–1376 mD, respectively. The diagenetic processes revealed the presence of authigenic clay and carbonate obstructing the pore spaces along with the occurrence of well-connected secondary and hybrid pores which eventually improved the reservoir quality of the Farewell sandstone. The well log analysis showed the presence of low shale volume between 10.9 and 29%, very good total and effective porosity values ranging from 19 to 32.3% as well as from 17 to 27%, respectively. The water saturation ranged from 22.3 to 44.9% and a significant hydrocarbon saturation fluctuating from 55.1 to 77.7% was also observed. The well log analysis also indicated the existence of nine hydrocarbon-bearing zones. The integrated findings from sedimentological and well log analyses verified the Farewell sandstone as a good reservoir formation.

Barite–Micromax mixture, an enhanced weighting agent for the elimination of barite sag in invert emulsion drilling fluids

Abstract: Weighting agents are mixed with the drilling mud to provide the high density required to control high-pressure high-temperature (HPHT) wells throughout the drilling operation. Solids sag occurs when the weighting agent separates from the liquid phase and settles down, causing variations in the drilling fluid density. This study evaluates barite–manganese tetroxide (Micromax) mixture to eliminate solids sag issue encountered with weighted invert emulsion drilling fluids at HPHT conditions. Micromax additive was added to barite-weighted fluids in different concentrations, 0, 15, and 30 wt% of the total weighting agent. Static and dynamic sag tests were used to evaluate the sag tendency of the new formulation under static and dynamic conditions. The performance of the new formulation was evaluated by measuring the electrical stability, density, rheological, viscoelastic, and filtration properties of the drilling fluid. The obtained results showed that Micromax additive improves drilling fluid stability by reducing the sag tendency. Adding only 30 wt% of Micromax additive eliminated barite sag issue in both dynamic and static conditions at 350 °F. 30 wt% Micromax increased the base fluid density by 5.4% and the yield point by 115% and maintained the gel strength value at 12 lb/100 ft2, while it reduced the plastic viscosity by 30%. The addition of Micromax additive improved the viscoelastic properties of the drilling fluid by maintaining a higher storage modulus to the loss modulus ratio when compared with the barite sample (in the range 4–4.5). Furthermore, 30 wt% Micromax improved the filtration performance by reducing the filtrate volume, filter cake weight, and filter cake thickness by 50%.

A simple NMR methodology for evaluating filter cake properties and drilling fluid-induced formation damage

Abstract: An efficient drilling fluid will form a filter cake that will minimize the drilling fluid invasion into any drilled formation. Drilling fluid must therefore be adequately evaluated in the laboratory prior to field trial. Filter cake properties such as thickness, porosity, permeability, and pore structure are frequently evaluated using several techniques such as CT scan, SEM, and XRF. However, each of these techniques can evaluate only one or two filter cake properties. This paper presents a simple but novel NMR technique to evaluate filter cake properties such as thickness, pore volume, porosity, and possibly permeability. Furthermore, the amount and particle size distribution of solids that invaded a given rock sample can be obtained using the same technique. The full procedure was tested and verified using four identical rock samples. Drilling fluid invasion and filter cake deposition experiments were conducted on each of the samples, using the same drilling fluid but four different concentrations of fluid loss additive. NMR T2 relaxation measurements were taken at three different stages of each rock sample: before filter cake deposition; after fluid invasion and filter cake deposition; and after filter cake removal. A material balance analysis of the probability density function and cumulative distribution function of the measured T2 profile at the different stages of each sample yielded multiple filtration loss properties of the filter cake. The results obtained showed high accuracy of the NMR versus the current techniques. Moreover, this current method evaluated the majority of the filter cake properties at the same time and in situ hence eliminated the need of using multi-procedures that disturb the sample state. Finally, the presented method can also be used to evaluate secondary damage associated with filter cake removal process.

Drilling stuck pipe classification and mitigation in the Gulf of Suez oil fields using artificial intelligence

Abstract: Developing a reliable classification model for drilling pipe stuck is crucial for decision-makers in the petroleum drilling rig. Artificial intelligence (AI) includes several machine learning (ML) algorithms that are used for efficient predictive analytics, optimization, and decision making. Therefore, a comparison analysis for ML models is required to guide practitioners for the appropriate predictive model. Twelve ML techniques are used for drilling pipe stuck such as artificial neural networks, logistic regression, and ensemble methods such as scalable boosting trees and random forest. The drilling cases of the Gulf of Suez wells are collected as an actual dataset for analyzing the ML performance. The key contribution of the study is to automate pipe stuck classification using ML algorithms and mitigate the pipe stuck cases using the genetic algorithm optimization. Out of 12 AI techniques, the results presented that the most reliable algorithm was extremely randomized trees (extra trees) with 100% classification accuracy based on testing dataset. Moreover, this research presents a public open dataset for the drilled wells at the Gulf of Suez to be used for the future experiments, algorithms’ validation, and analysis.

Experimental study of the performances of commercial surfactants in reducing interfacial tension and wettability alteration in the process of chemical water injection into carbonate reservoirs

Abstract: Surfactants are used in the process of chemical water injection to reduce interfacial tension of water and oil and consequently decrease the capillary pressure in the reservoir. However, other mechanisms such as altering the wettability of the reservoir rock, creating foam and forming a stable emulsion are also other mechanisms of the surfactants flooding. In this study, the effects of three commercially available surfactants, namely AN-120, NX-1510 and TR-880, in different concentrations on interfacial tension of water and oil, the wettability of the reservoir rock and, ultimately, the increase in oil recovery based on pendant drop experiments, contact angle and carbonate core flooding have been investigated. The effects of concentration, temperature, pressure and salinity on the performances of these surfactants have also been shown. The results, in addition to confirming the capability of the surfactants to reduce interfacial tension and altering the wettability to hydrophilicity, show that the TR-880 has the better ability to reduce interfacial tension than AN-120 and NX-1510, and in the alteration of wettability the smallest contact angle was obtained by dissolving 1000 ppm of surfactant NX-1510. Also, the results of interfacial tension tests confirm the better performances of these surfactants in formation salinity and high salinity. Additionally, a total of 72% recovery was achieved with a secondary saline water flooding and flooding with a 1000 ppm of TR-880 surfactant.

Artificial neural network model for predicting the density of oil-based muds in high-temperature, high-pressure wells

Abstract: In this paper, an artificial neural network model was developed to predict the downhole density of oil-based muds under high-temperature, high-pressure conditions. Six performance metrics, namely goodness of fit (R2), mean square error (MSE), mean absolute error (MAE), mean absolute percentage error (MAPE), sum of squares error (SSE) and root mean square error (RMSE), were used to assess the performance of the developed model. From the results, the model had an overall MSE of 0.000477 with an MAE of 0.017 and an R2 of 0.9999, MAPE of 0.127, RMSE of 0.022 and SSE of 0.056. All the model predictions were in excellent agreement with the measured results. Consequently, in assessing the generalization capability of the developed model for the oil-based mud, a new set of data that was not part of the training process of the model comprising 34 data points was used. In this regard, the model was able to predict 99% of the unfamiliar data with an MSE of 0.0159, MAE of 0.101, RMSE of 0.126, SSE of 0.54 and a MAPE of 0.7. In comparison with existing models, the ANN model developed in this study performed better. The sensitivity analysis performed shows that the initial mud density has the greatest impact on the final mud density downhole. This unique modelling technique and the model it evolved represents a huge step in the trajectory of achieving full automation of downhole mud density estimation. Furthermore, this method eliminates the need for surface measurement equipment, while at the same time, representing more accurately the downhole mud density at any given pressure and temperature.

Conventional and electrical EOR review: the development trend of ultrasonic application in EOR

Abstract: A small portion of oil can be extracted during primary and secondary stages of oil production, and significant quantities of oil remain in reservoirs Enhanced oil recovery methods are used to extract the trapped oil with high viscosity in reservoirs and improve the efficiency of the production wells Ultrasonic-based enhanced oil recovery method has become of considerable interest to researchers in recent years This paper mainly presents the in-depth literature review of ultrasonic wave to investigate its application development trend in enhanced oil recovery Besides, it also presents an overview of conventional enhanced oil recovery techniques such as chemical, gas, and thermal methods and nonconventional techniques such as electromagnetic and microwave heating The results exhibit an increasing implementation of the ultrasonic waves for oil recovery since it is an inexpensive and ecologically sound method, can be applied in any type of reservoir, protects the well against damage, prevents heat loss, and enables stimulation freely

Real-time prognosis of flowing bottom-hole pressure in a vertical well for a multiphase flow using computational intelligence techniques

Abstract: An accurate prediction of well flowing bottom-hole pressure (FBHP) is highly needed in petroleum engineering applications such as for the field production optimization, cost per barrel of oil reduction, and quantification of workover remedial operations. A good number of empirical correlations and mechanistic models exist in the literature and are frequently used in oil industry to estimate FBHP. But majority of the empirical models were developed under a laboratory scale and are therefore inaccurate when scaled up for the field applications. The objective of this study is to present a new computational intelligence-based model to predict FBHP for a naturally flowing vertical well with multiphase flow. The present study shows that the accuracy of FBHP estimation using PSO-ANN is better than the conventional ANN model. A small average absolute percentage error of less than 2.1% is observed with the proposed model, while comparing the previous empirical correlations and mechanistic models on the same data gives more than 15% error. The new model is trained on a surface production data, which makes the prediction of FBHP in a real time. A group trend analysis tests were also carried out to assure that the proposed model is accurately capturing the underline physics behind the problem.

Molecular simulation and microtextural characterization of quartz dissolution in sodium hydroxide

Abstract: This study uses empirical experimental evidence and Material Studio simulations to explain the interaction of sodium hydroxide (NaOH) with quartz Density functional theory (DFT) calculations were carried out using the Cambridge Serial Total Energy Package In addition, quartz grains subjected to dissolution in NaOH were characterized using scanning electron microscopy The so-called O-middle termination in the quartz tetrahedron structure, typified by a solitary exposed oxygen atom at the surface, is the most susceptible SiO2 terminations to NaOH attack, as it is associated with the lowest surface energy The adsorption energy values are − 144 kcal/mol and − 590 kcal/mol for a single atom layer and five-layered atomic structure, respectively The DFT calculation reveals intramolecular energy is the dominant adsorption energy, followed by a weak van der Waals energy The NaOH adsorbed on quartz (001) surface constitutes a lower band gap of 0138 eV compared to cleaved quartz (001) surface (0157 eV) In addition, the energy range of NaOH adsorbed on quartz is wider (− 50 to 10 eV), compared to (001) quartz (− 20 to 11 eV) The dissolved quartz showed the precipitation of sorbed silicate phases due to incongruent reactions, which indicates new voids and etch pits can be created through the cleaving of the sodium silicates sorbed into the quartz surface The adsorption energy for NaOH interactions with reservoir sandstone was significantly higher compared to the solitary crystal grains, which can be attributed to the isotropic deformation of a single crystal, and non-uniform deformations of adjacent grains in granular quartz of sandstone reservoir It can be inferred that exposure to NaOH will affect the structure and reactivity of quartz The quartz surface textural study indicates that dissolution of crystalline (granite) and clastic rocks (sandstone) is critical to the development of voids, which will improve permeability by providing channels and routes for the passage of hydrothermal and reservoir fluids

A review of experimental studies on sand screen selection for unconsolidated sandstone reservoirs

Abstract: Sand production is a problem that affects hydrocarbon production from unconsolidated sandstone reservoirs. Several factors, such as the strength of the reservoir, its lithification and cementation and reduction in pore pressure, may cause sand to be separated from the rock and transported by hydrocarbons to the well. Producing sand commonly causes erosion and corrosion of downhole and surface equipment, leading to production interruptions and sometimes forces operators to shut-in wells. Several different methods of sand control are available to reduce the impact of sand production. The reviewed papers suggest that the most suitable methods for unconsolidated sandstone reservoirs are stand-alone screens and gravel packs. Because of the cost and complexity of gravel packs, stand-alone screens are usually the first choice. These screens have different geometries, and selection of the most suitable screen depends on the particle size distribution of the grains in the formation and other reservoir and production parameters. A screen retention test, run in a laboratory with screen samples and typical sands, is often used to ensure that the screen is suitable for the reservoir. This paper reviews the main causes of sand production, the properties of unconsolidated sandstones that predispose reservoirs to sand production problems and the selection criteria for the most suitable mitigation method. The process of selecting a screen using experimental screen retention tests is reviewed, and the limitations of these tests are also discussed. Some numerical simulations of experimental tests are also reviewed, since this represents a very cost-effective alternative to laboratory experiments.

Flow units and rock type for reservoir characterization in carbonate reservoir: case study, south of Iraq

Abstract: The current work is focused on the rock typing and flow unit classification for reservoir characterization in carbonate reservoir, a Yamama Reservoir in south of Iraq (Ratawi Field) has been selected, and the study is depending on the logs and cores data from five wells which penetrate Yamama formation. Yamama Reservoir was divided into twenty flow units and rock types, depending on the Microfacies and Electrofacies Character, the well logs pattern, Porosity–Water saturation relationship, flow zone indicator (FZI) method, capillary pressure analysis, and Porosity–Permeability relationship (R35) and cluster analysis method. Four rock types and groups have been identified in the Yamama formation depending on the FZI method, where the first group represents the bad reservoir quality (FZI-1) (Mudstone Microfacies and Foraminiferal wackestone Microfacies), the second group reflects a moderate quality of reservoir (FZI-2) (Algal wackestone–Packstone Microfacies and Bioclastic wackestone–Packstone Microfacies), the third group represents good reservoir quality (FZI-3) (Peloidal Packstone–Grainstone Microfacies), and the fourth group represents a very good reservoir quality (FZI-4) (Peloidal–oolitic Grainstone Microfacies). Capillary pressure curves and cluster analysis methods show four different rock types: a very good quality of reservoir and porous (Mega port type) (FZI-4) (Peloidal–oolitic Grainstone Microfacies) with a low irreducible Water saturation (Swi), good quality of reservoir and porous (Macro port type) (FZI-3) (Peloidal Packstone–Grainstone Microfacies), moderate quality of reservoir (Meso port type) (FZI-2) (Algal wackestone–Packstone Microfacies and Bioclastic wackestone–Packstone Microfacies), and a very fine-grained with bad reservoir quality (Micro port type) (FZI-1) (Mudstone Microfacies and Foraminiferal wackestone Microfacies) and with the higher displacement of pressure). These capillary pressure curves support the subdivision of the main reservoir unit to flow units.

Experimental study of the relationship between porosity and surface area of carbonate reservoir rocks

Abstract: Over the time by increasing global demand for source of energy and decreasing hydrocarbon production from reservoirs, recovery methods have become important. The surface area and porosity are central physical characteristics that highly affect the estimation of original oil and gas in place and understanding the mechanisms incorporating in production. The surface area is the internal surface area per unit of pore volume and determines the amount of space in rocks exposed to injectant during injection operation. The occurrence of fractures system in carbonated reservoirs increases the complexity and decreases the homogeneity; hence, it is difficult to determine the correct surface area of reservoir. Therefore, the existence of a local correlation which relates effective porosity to specific surface area is needed and it can help to estimate effective surface area exposed to chemicals during Enhanced Oil Recovery (EOR) process. In this study, the specific surface area in carbonate reservoir rocks was measured by gas adsorption (nitrogen) method and petro-graphical image analysis. In addition, the effective porosity was determined by a gas porosimeter, followed by plotting specific surface area measured by the Brunauer, Emmett and Teller (BET) method versus specific surface area determined from core scan and calibration curve. According to this calibration curve, a new relationship was developed (with R2 = 0.92) that could give BET data for a known data of core scan. The relationship between porosity and specific surface area was analyzed statistically and a relationship with accuracy of R2 = 0.89 was proposed. This relationship was compared with other models such as Pirson and Kotyakhov. Results show that the latter one is more accurate than other models and is more compatible with experimental data (with R2 = 0.84). The results obtained from the experiment indicate that the specific surface area shows an initial decrease upon increasing of porosity up to 0.2. After this decrease, the curve indicates an increasing trend. Moreover, a novel relationship was developed depending on the specific surface area, porosity and permeability and some constant parameters for carbonate rocks (with R2 = 0.95).

Formation damage induced by wax deposition: laboratory investigations and modeling

Abstract: There are oil fields, wherein favorable conditions for the formation damage induced by wax deposition are created during production. The damage can be expressed by a decrease in porosity and permeability and a reduction in the drainage area. There are only a few unconventional fields, and this makes them unique. To prevent this complication, it is necessary to control the field production. Assuming the presence of such problem, the conventional reserves may turn into difficult oil reserves whose production is problematic, which will compromise the project profitability. The key to the problem is associated with the experimental procedure and research conditions for investigation wax crystallization in oil, being the subject of this paper. The authors showed that the use of WAT measurement technique in an open measuring system is not enough to control wax deposition in the reservoir pore volume. Based on the results of the flooding technique and micro-computed tomography, a digital core, that allows to simulate fluid flow in the porous medium of the core before and after formation damage, has been created. The calculation of the change in the thermal field around the injection well over time, according to the extended Lauwerier’s concept, has been carried out. WAT of a wax-bearing solution was measured by the rheology method using an open measuring system (plate-to-plate measuring system under atmospheric pressure), and the dependence of viscosity versus temperature was obtained during experimental studies. The temperature was decreased from 60 to 10 °C at a cooling rate of 1 °C/min. The experiment was carried out at atmospheric pressure and a shear rate of 5 s−1. Also, filtration technique and micro-computed tomography were used. The dependence of the pressure gradient versus temperature and the pore throat diameter distribution functions for the initial core and core with organic scales were obtained. The flooding experiment was carried out at a constant flow rate of 0.5 cm3/min and confining pressure of 4.1 MPa. The temperature was decreased from 40 to 33 °C at a cooling rate of 1 °C/h. The inflection points on the curves viscosity versus temperature and pressure gradient versus temperature confirm the WAT. The results of the laboratory experiments showed that WAT, measured by the rheology method is 3–4 °C lower than WAT, measured by the flooding technique. The results of the micro-computed tomography showed that initial porosity decreased from 9.0 to 2.1% as a result of wax deposition. The pore throats with diameters from 20 to 70 μm are involved in the clogging with wax. The calculation results confirmed the possibility of cooling the near-wellbore area of injector to a temperature equal to WAT and the cold front movement to the producing wells. The production profiles calculated based on the models of porosity and permeability reduction, showed that wax deposition in the near-wellbore area can cause a significant decrease in the productivity index. An effective remediation technology for injection wells was proposed.

The influence of moisture content on coal deformation and coal permeability during coalbed methane (CBM) production in wet reservoirs

Abstract: Moisture adsorption in the coal seams affects the gas adsorption capacity and can alter the coal deformation and permeability criteria of the coal seam. The effect of dynamic loss of moisture content, both on moisture and gas sorption-induced coal swelling/shrinkage strains, during the coalbed methane (CBM) production, is crucial. This study investigates the interactions among coal matrix, absorbed gas, and moisture content, based on the coal swelling/shrinkage strains and gas adsorption decay criteria. Consequently, a mathematical model of the coal deformation is developed for the proper evaluation of the moisture effect. For developing the model, this paper considers the standard gas flow and moisture loss equations to assess the volumetric content, equilibrium pressure, and density of the moisture. Finally, it comprehensively analyzes the sensitive factors and effects of elemental parameters of moisture content on coal deformation and coal permeability. The results show that moisture content at adsorbed state significantly changes the coal swelling/shrinkage strain and that distorted swelling and shrinkage characteristics can promote the permeability alternation in wet coal reservoirs. Moreover, the intermolecular attraction between the coal structure and the moisture content has a significant effect on methane adsorption/desorption-induced deformation in coal structure. This study also designs the coal deformation strains as a function of moisture content by the Langmuir type model and evaluates the hysteresis rate between the swelling and shrinkage characteristics. The findings of this paper can characterize a wet coal reserve for CBM production and anticipate future production under different operating conditions.