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Summary Liquid-liquid phase flow in pipes merits further investigation as a challenging issue that has very rich physics and is faced in everyday applications. It is the main problem challenging the fluid flow mechanism in the oil and gas industry. The pressure gradient of liquid flow and flow pattern are still the topics of numerous research projects. In this paper, the emphasis is on further investigation to research the flow pattern, water holdup (HW), and pressure decrease for vertical, horizontal, and inclined flow directions of oil and water flows. Test section lines of 4.19-in. (106.426 mm) inner diameter (ID) and 5-m horizontal, 5-m inclined, and 5-m vertical test sections were serially connected. The experiments were conducted at 40°C using 2-cp viscosity oil and tap water, and oil density of 850 kg/m3, at the standard conditions. Fifty experiments were executed at 250 kPa at the multiphase flow test facility, with horizontal, upward (0.6° and 4°), downward (−0.6° and −4°) hilly terrain and vertical pipes. The oil and water superficial velocities were changed between 0.03 and 2 m/s. This evidence was obtained using video recordings; the flow patterns were observed, and the selection of each flow pattern was depicted for each condition. For horizontal and inclined flow, new flow patterns were documented (e.g., oil transfer in a line forms at the top of the pipeline, typically at high water rate, and water transfer at the lower part of the pipe at a high oil rate). The data were taken at each flow condition, resulting in new holdup and pressure drop. The results show that the flow rate and the pipe inclination angle have major impacts on the holdup and pressure drop performances. In the vertical flow, a clear peak was demonstrated by experiments after the superficial oil velocity reached a certain value. This peak is known as phase inversion point, where after this peak, the pressure starts declining as the superficial oil velocity increases. Also, slippage has been observed after varying inlet oil flow rates between the two phases. The experiments showed that with minor alteration in the inclination angle, the slippage was significantly changed. This study presented new experimental results (measured mainly at horizontal, inclined, and vertical flow conditions) of HW, flow pattern, and pressure drop. These findings are key evidence of the evolving oil-water and flowline estimate models.

Hydrolyzed polyacrylamide (HPAM) is a commonly used polymer for the chemicals, mining and refining processes of hydrocarbon but suffers from a persistent high-temperature instability problem. In contrast, the nanoparticle suspension remains a technical challenge because of the strong interactions of van der Waal forces within nanoparticles, which always encourage aggregation. This research sought to improve nanoparticles (NP) stability and polymer (HPAM) rheological properties to improved hydrocarbon recovery by utilizing synthesized graphene oxide (GO) nanosheets and fumed Aerosil 380 Silica oxide (SiO2). The aqueous nanocomposites based on HPAM-GO and HPAM-SiO2 in aqueous polymeric solutions have been developed, and its viscoelastic and static behaviour is studied. The results imply that by adding fumed silica NP, the viscoelastic behaviour of HPAM is marginally improved, particularly in high temperatures and salinity, however, the inclusion of GO's significantly improves the viscosity and stability of the base polymer fluid at high temperatures. The Fourier data for the transformation of the infrared spectrum confirmed that the hydrogen bonding formed between HPAM carbonyl groups and silica NP surface silanol functionality and covalent interlinking of electrostatic h-bonding between HPAM and functional GO contributed to the improved stabilization and improved rheological performance that helps to recover high salinity and temperature hydrocarbons.

In enhanced oil recovery, different chemical methods utilization improves hydrocarbon recovery due to their fascinating abilities to alter some critical parameters in porous media, such as mobility control, the interaction between fluid to fluid, and fluid to rock surface. For decades the use of surfactant and polymer flooding has been used as tertiary recovery methods. In the current research, the inclusion of nanomaterials in enhanced oil recovery injection fluids solely or in the presence of other chemicals has got colossal interest. The emphasis of this review is on the applicability of nanofluids in the chemical enhanced oil recovery. The responsible mechanisms are an increment in the viscosity of injection fluid, decrement in oil viscosity, reduction in interfacial and surface tension, and alteration of wettability in the rock formation. In this review, important parameters are presented, which may affect the desired behavior of nanoparticles, and the drawbacks of nanofluid and polymer flooding and the need for a combination of nanoparticles with the polymer are discussed. Due to the lack of literature in defining the mechanism of nanofluid in a reservoir, this paper covers majorly all the previous work done on the application of nanoparticles in chemical enhanced oil recovery at home conditions. Finally, the problems associated with the nano-enhanced oil recovery are outlined, and the research gap is identified, which must be addressed to implement polymeric nanofluids in chemical enhanced oil recovery.

Drilling mud’s rheological characteristics, such as plastic viscosity and yield point, are adversely affected with an inappropriate mud formulation. Native starch is one of the most important components in water-based mud because it improves the rheological and filtration characteristics of the mud. The native starch stability under various temperature and exposure time regimes is an important concern for utilizing starch in oil and gas drilling operations. In this work, tapioca starch was modified using carboxymethylation for the first time in order to improve its performance in non-damaging water-based muds. The modified starch was characterized by Fourier-transform infrared spectroscopy and X-ray diffraction. The thermal stability was tested using thermal gravimetric analysis. Various mud blends were formulated based on the experimental design using response surface methodology (RSM) to investigate their performance at various temperature conditions. Thirty experimental runs were carried out based on the selected factors and responses considering the optimal (custom) design, and the results were analyzed through ANOVA. The Fourier-transform infrared spectroscopy and X-ray diffraction results confirmed the carboxymethylation of starch. The TGA analysis revealed strong thermal stability after modification. Additionally, the Power law model (PLM) described the obtained rheological data for the selected formulations, resulting in determination coefficients of more than 0.95. Furthermore, the examined samples showed a reduction in the flow behavior index from 0.30 to 0.21 and an increase in the consistency index from 5.6 to 15.1. Optimization and confirmation results revealed the adequacy of the generated empirical models for both plastic viscosity and yield point. The obtained consistency index values provided a direct relationship with the modified starch concentration, indicating an improvement in the cutting carrying capacity of mud. Based on the current literature survey, the studied formulation has not been reported in the literature.

The unconventional reservoir geological complexity will reduce the drilling bit performance. The drill bit poor performance was the reduction in rate of penetration (ROP) due to bit balling and worn cutter and downhole vibrations that led to polycrystalline diamond compact (PDC) cutter to break prematurely. These poor performances were caused by drilling the transitional formations (interbedded formations) that could create huge imbalance of forces, causing downhole vibration which led to PDC cutter breakage and thermal wear. These consequently caused worn cutter which lowered the ROP. This low performance required necessary improvements in drill bit cutter design. This research investigates thermal–mechanical wear of three specific PDC cutters: standard chamfered, ax, and stinger on the application of heat flux and cooling effect by different drilling fluids by using FEM. Based on simulation results, the best combination to be used was chamfered cutter geometry with OBM or stinger cutter geometry with SBM. Modeling studies require experimental validation of the results.

In multiphase flow engineering operations, the pipelines that convey viscous fluids are subjected to interior friction where the pipe wall meets the fluid. The friction on the inner surface of the pipe causes energy losses. The losses are exhibited as a progressive pressure drop over the length of the pipe that varies with the fluid flow rate. This study develops a computational method to estimate the pressure change at any flow condition of multiphase flow (oil, gas, and water) inside a vertical pipe by developing fluid mechanics equations and using empirical correlations. Darcy and Colebrook friction factor correlations were used to ratify the predicted frictional pressure drop by computational method outcomes. OLGA dynamic simulation software was used to validate the accuracy of the computational method results. A sensitivity analysis was performed to evaluate the performance of the developed computational method, by using different well flow rate, pipe size diameter, and fluid properties. The frictional pressure drop estimation by computational method has acceptable accuracy and it is located within the accepted average relative error band (±20%). The overall performance of the method is satisfactory when compared with other observations.

The prediction of fluid flow rates is of prime importance for the oil and gas business. Several classical flow rate prediction correlations have been generated and generally used for wells flowing naturally. However, for oil wells flowing artificially, these correlations overlooked many significant fluid and well parameters, leading to erroneous results and inaccurate predictions. This paper used the outputs of a new mathematical model to predict the flow rates of 34 electrical submersible pump (ESP) oil wells from 3 oil fields located in North Africa, possessing a broad range of parameters, to determine a new correlation to predict the oil flow rate. Mathematical procedures for finding the best-fitting curve were used. When compared to the experimentally measured results of another two datasets, the predicted oil flow rates by the new correlation were in good agreement. Indeed, the performance of the new correlation shows reliable prediction results with about ± 10% relative error. Furthermore, the results of this new method were statistically superior to results from previous correlation methods. The correlation that was proposed here exhibits greater accuracy (−5% error) than existing previous correlation methods. The new correlation adapts itself to any ESP oil well and could apply to both onshore and offshore wells.

Spontaneous imbibition (SI) is the principal production mechanism in naturally fractured reservoirs produced by waterflooding and is essential for fluid flow characterization to predict their future performance. As an alternative to the expensive, time-consuming laboratory measurements, 2D images render a different prospect to obtain SI capillary pressure curves, especially for tight reservoirs. This paper introduces a unique approach to infer SI capillary pressure curves from 2D images through integrating image analysis and fractal theory. Using pore-related information obtained from image analysis, we properly represent the pore structure as bundles of tortuous square and triangular tubes with sinusoidally varying radii to imitate cross-sectional variation between pore bodies and throats. Moreover, we simulate the piston-like and snap-off displacement mechanisms to derive an innovative fractal SI capillary pressure model. The developed model considers the contact angle hysteresis caused by surface roughness and heterogeneity of reservoir rocks. The Mayer-Stowe-Princen (MSP) approach is implemented to compute the entry capillary pressure of piston-like displacement. The laboratory-measured porosity and permeability are utilized to determine the model's 3D-related parameters that cannot be inferred from 2D images. The model reliability is verified with the good accuracy of the predicted capillary pressure curves versus laboratory-measured data of five samples from the Liushagang and Huangliu in the South China Sea. Finally, the fundamental parameters influencing the developed SI capillary pressure model are investigated with sensitivity analysis.

This paper presents the use of response surface methodology (RSM) and robust supervised machine learning approaches to model nano-polymeric viscosity. In the absence of studies in the previous research on using these two techniques, this study's key objective was to equate these strategies' efficiency with a nano-polymer solution's viscosity modelling. Synthesized nano-polymer composite is characterized by scanning electron microscope, transmission electron microscope, X-ray diffraction, and thermogravimetric analysis. The research used the Split-Plot Central Composite Design (SP-CCD) of RSM to model five independent parameters for nano-polymeric composite viscosity, namely shear rate, temperature, and concentration nanoparticles, sodium chloride, and calcium chloride. The findings indicate that the polymer solution's viscosity was not equally crucial to all parameters. Besides, a variance analysis (ANOVA) was conducted, and no evidence of inadequacy in the RSM model was provided. The comparative study of the conventional central composite design model and the supervised machine learning model was conducted. The split-plot central composite model gave R2 of 92% and adjusted R2 of 88%. Amongst all supervised machine learning models used, the XGBoost model recorded the highest R2 accuracy of 90% and lowest prediction errors in terms of mean absolute error and root mean square error. XGBoost when compared to other models in terms of akaike information criterion had the highest likelihood of fit making it the best option in analyzing rheological behavior for hybrid polymeric nanofluid.

Higher fluid loss volumes and suspension capability are the critical shortcomings of water-based muds. It can promote problems during drilling operations. The rheological and filtration properties of all drilling muds have been continually considered the essential characteristics for a successful drilling operation. Various irreversible problems are directly associated with drilling fluids rheological and filtration properties such as differential sticking, formation damage, borehole instability and uncontrollable formation fluids intrusion to the wellbore. Drilling fluid is closely associated with the complications or solutions of the mentioned problems. The control of such properties is of paramount importance, especially at high temperature conditions of the wellbore. This study aims to formulate a low-solid drilling fluid for better performance by replacing bentonite in conventional fluids with an equal amount of xanthan gum and tapioca starch. The effects of tapioca starch on rheological and filtration characteristics of water-based muds (WBMs) in static conditions have been investigated at different temperatures and pressures. Various mud blends were prepared containing tapioca starch (TS) and polyanionic cellulose (PAC) in the presence of xanthan gum (XG) at different replacement levels. The impact of tapioca starch on rheological and filtration characteristics were evaluated using rheometer, filterpress (LPLT and HPHT) and scanning electron microscope (SEM). The presence of tapioca starch significantly improved rheological and filtration characteristics of water-based muds (WBMs) and revealed that the low solid blends unveiled an obvious shear thinning behavior. Shear stress (σ) versus shear rate (s−1) data of optimized mud samples was best fitted to the Power Law model with R2 of 0.99. The flow behavior index was decreased from 0.47 to 0.21, while the consistency index was increased from 0.31 to 4.45 with the addition of tapioca starch. Rheological properties were improved with the starch concentration and were found within the American Petroleum Institute (API) recommended range. Filtrate volume for the samples containing tapioca starch in 14 ppb was found 4 ml at a temperature of 212 °F. Filtercake thickness was measured 0.27 mm with the maximum concentration of tapioca starch. SEM images confirmed the tapioca starch showed a slick and compact filtercakes at the temperature of 212 °F. This research helps to encourage the use of biodegradable and renewable additives in drilling fluids for the exploitation and production of hydrocarbons.

Obtaining geophysical data is a time consuming and costly activity. Also, depending on the exploration stage, there is few data available and it is not even possible to obtain new data (for the duration of the bidding phase). One of the general strategies in the industry is to use existing known information from similar reservoirs (analogues) to better determine the missing data, to get more information about the target area. Therefore, the technical team, geologist and reservoir engineers must evaluate all accessible data types such as seismic, well logs, well testing, production data, cores and analogues data available, to make the best technical and business decisions in exploration and production operations process.

To identify some of the concepts in this book, we need to understand play, lead, and prospect.

Exploration is a costly and risky operation as the expenditure associated are generally valued at millions of dollars and every two out of three wells, on average, contain no shows of hydrocarbons. Consequently, the exploration companies need to drill more wells in one area to find an oil or gas discovery, and this might take more years.

This chapter will show some case studies from offshore deepwater oil and gas fields at several depths as well as different field development options such as standalone hosts and tie-backs.

After identifying potentially feasible fields and at the beginning of an oil field development plan, once the oil field dimensions have been allocated, engineers determine the number of wells needed to meet production requirements and the method of extraction of the liquid hydrocarbons.

This chapter is discussing the expenditures associated to all investment (CAPEX) that is made in advance, and the operational expenses (OPEX) that will occur from the first day startup the production until the abandonment day. Roughly numbers will be presented for these expenses in deepwater projects and will see what is the key assumptions must be considered when keying these values to any project. Accessible records that cover these values will be revealed together with the approximation costs and methodology.

This chapter presents upstream production facilities and subsea engineering design of oil-handling systems and along with the capital expenditure costs. Several operations activities will be covered including floating production facilities, tiebacks flow lines, types of hosts, export pipelines, and manifolds. Besides, will know how to choice and consider the optimum facilities and evacuation systems.

Reservoir rock and fluid properties are the vital parameters that control the estimation of the original oil and gas in place and the recoverable oil and gas.

The overall pressure at any formation depth, as a result of the weight of fluid-saturated rock column, is known as overburden pressure, Pov.

Saturation is defined as the ratio of the fluid volume in the porous medium to the pore volume of the rock. That means, saturation is the proportion of interrelated aperture full by a specified phase. For a gas-oil-water system. Therefore, the following formulas show the saturation ratio for every single phase in the porous medium

Currently, there are numerous of authors defined the fracture from a different perspective, However, from the geo-mechanical viewpoint; a fracture is defined as a surface in which a loss of solidity has taken place.

The most prominent features of reservoir rock are porosity, permeability, and fluid saturations. These properties related to the pore media system and its fluid distribution and flow forms. By carrying out laboratory analyses, using core samples, reservoir rock properties can be investigated.

In this chapter will present an overview of unconventional natural resources definitions and assessment. In this chapter will present an overview of unconventional natural resources definitions and assessment. Whereas, a different characterization have been presented to defined most of the unconventional reservoirs.

Reliable capillary pressure data are required for reservoir simulation and fluid flow characterization in porous media. The capillary pressure is commonly measured in the laboratory, which is costly, challenging, and accompanied by measurement uncertainties, especially for low-permeability core samples. Besides laboratory measurements, two-dimensional (2D) rock images reveal another prospect to obtain capillary pressure curves. This paper presents a new integrated approach combining image processing and fractal theory to infer the capillary pressure curve from 2D rock images in low-permeability sandstone. Our approach’s unique feature is its new representation of the pore structure based on information extracted from 2D cross-sections using image processing techniques (i.e. image segmentation and watershed partitioning). Furthermore, we derived an innovative analytical fractal model to calculate the capillary pressure from the newly proposed pore system representation. A new tortuous length equation is introduced to eliminate the developed fractal models’ dependency on the straight capillary length. The pore fractal dimension is computed using the box-counting method from the processed 2D image. The tortuosity fractal dimension is obtained from solving the developed fractal equations of porosity and permeability with the corresponding laboratory measurements. Additionally, a procedure for inferring capillary pressure from multiple cross-sections is proposed. The good accuracy in predicting capillary pressure for five low-permeability sandstone core samples demonstrates the developed approach’s robustness.

The most promising method to improve chemical oil recovery via wettability alteration is associated with colloidal solution such as nanofluid. However, nanofluids show limitations due to nanoparticle agglomeration which may result into pore blockage during its injection in a porous media. The unsuccessful recovery of injected nanoparticles has increased their footprints, which is becoming a serious environmental issue. Therefore, this study reports the use of a co-stabilizer i.e. TiO2 (0.05 and 0.1 wt%) that not only reduces nanoparticle agglomeration in silica nanofluid (SiO2, 0.5 wt%) but also improves its wetting property and oil recovery from synthetic sand-packs of porosity = ∼29–33% and permeability = ∼700–800 mD. In nanofluid synthesis, polymer polyacrylamide was used as base fluid and surfactant [anionic: sodium dodecylsulfate and nonionic: triton x 100] was used to find improvements in wettability alteration, interfacial tension reduction, and oil recovery results of nanofluid. With surfactant, the wetting property of STN (SiO2–TiO2 nanofluid) was found superior (strong water-wet) as confirmed by maximum (67%) reduction in contact angle. Also, interfacial tension of crude oil reduced by ∼91% which increased the chemical oil recovery by ∼78% from sand-pack. Importantly, nanofluid use in porous media is associated with environmental concern. Therefore, each nanofluid was repetitively (3 times) flooded through sand-pack and NP retention was examined using three different characterization methods (contact angle, ultraviolet visible, and field emission scanning electron microscopy) and suitably compared to find least nanoparticle retention in porous media. For surfactant treated nanofluids, nanoparticle retention of 0.03–0.07 wt% was determined while its value was significantly higher (0.31 wt%) for conventional SiO2 nanofluid. Finally, this study suggests that nanoparticle retention of conventional silica nanofluid can be reduced through the selection of a proper co-stabilizer that may help to protect subsurface from pore blockage and other associated environmental issues.

Development of a mathematical solution for injection/falloff problem of an oil-water system for transient data analysis is complicated due to the presence of two mobile phases that create a moving discontinuity. The solutions that have been developed in the past are based on a series of assumptions that make the models limited. The previous models have neglected one or more of the key reservoir and well parameters such as the variation of saturation in the invaded zone, temperature effects, wellbore storage, skin and outer boundary conditions. In this work, a generalized two-step semi-analytical solution method is presented to precisely simulate the pressure transient behaviour for injection and falloff tests following cold water injection for a fully-penetrating vertical well in a warm and bounded oil reservoir in the presence of skin and wellbore storage. The formulated model uses two simplistic steps to solve the complex mathematical problem and improve computational efficiency. The usage of the Laplace-transform finite-difference method to solve the system of equations eliminates the need for temporal discretization, thereby resolving issues related to convergence and time iterations by allowing an unlimited timestep size without the loss of stability and accuracy. The accuracy and consistency of the proposed solution method are assessed by comparing the results with that of ECLIPSE 100 and an excellent agreement is observed. The results suggest that the injection period pressure behaviour is vastly influenced by the injected water propagation under cold conditions, whereas, the falloff period pressure behaviour provides information of the water bank under cold conditions and the uninvaded zone under hot conditions. The comparison of the non-isothermal and isothermal pressure behaviour shows that the isothermal model can be improved using modified fluid viscosities to match the non-isothermal pressure behaviour that not only could minimize the mathematical complications, but also the computation time.