Formation damage has the potential to impair and weaken reservoir productivity and injectivity, causing substantial economic losses. Oil and gas wells can be damaged by various mechanisms, such as solid invasion, rock–fluid incompatibilities, fluid–fluid incompatibilities, and phase trapping/blocking, which can reduce natural permeability of oil and gas near the wellbore zone. These can happen during most field operations, including drilling operations, completion, production, stimulation, and enhanced oil recovery (EOR). Numerous studies have been undertaken in recent years on the application of nanotechnology to aid the control of formation damage. This review has found that nanotechnology is more successful than traditional materials in controlling formation damages in different phases of oil and gas development. This is facilitated by their small size and high surface area/volume ratio, which increase reactivity and interactivity to the adjacent materials/surfaces. Furthermore, adding hydrophilic nanoparticles (0.05 wt %) to surfactants during EOR alters their wettability from 15 to 33%. Wettability alteration capabilities of nanoparticles are also exemplified by carbonate rock from oil-wet to water-wet after the concentration of 4 g/L silica nanoparticles is added. In addition, mixing nanoparticles to the drilling fluid reduced 70% of fluid loss. However, the mechanisms of impairment of conductivity in shale/tight formations are not consistent and can differ from one formation to another as a result of a high level of subsurface heterogeneity. Thus, the reactivity and interaction of nanoparticles in these shale/tight formations have not been clearly explained, and a recommendation is made for further investigations. We also recommend more nanotechnology field trials for future research because deductions from current studies are insufficient. This review provides more insights on the applications of nanoparticles in different stages of oil and gas development, increasing our understanding on the measures to control formation damage.

Nanomaterials have been used in the oil and gas industry to improve thermal stability, rheology properties, and reactivity through fluid dispersion into the formation. Nanomaterials in producing wells can control formation damage near the wellbore regions. Foreign fluid invasion to the reservoir rock during drilling, fracturing, completion, enhanced oil recovery, and workover causes an interaction with the rock formation and fluids. This results in formation damage such as clay swelling and deflocculation, solid particle invasion, and asphaltene precipitation, all of which reduce production and lead to significant economic losses. In this review, we present the application of nanomaterials to oilfields as a way of optimizing production with minimal formation damage near the wellbore regions. Also, this review presents how the laboratory experiments from nanomaterials were upscaled to oilfields. The different types of nanomaterials used to control formation damage across producing fields around the world were investigated. This study has shown that nanomaterials are more effective than traditional materials to be used in oilfields for controlling formation damage during various stages of oil and gas development and it recommends that the effect of the relationship between nanoparticle size and type should be explored for effective application. However, because formation damage is caused for a variety of reasons, this work points out that many types of nanomaterials need to be combined to achieve multipurpose mitigation. Furthermore, more research concerning the dispersion of nanoparticles in cement slurry and fracturing fluid should be undertaken.

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Summary The experimental design of well cement with durable compressive strength (CS) is challenging and time-consuming. The current research predicts CS using the enhanced group method of data handling via a modified Levenberg-Marquardt algorithm (GMDH-LM) with experimental data. Class F fly ash (CFFA) is used as a supplementary material to cement at various proportions. Experimental tests of CS, thermogravimetric (TG) analysis, rheology, and scanning electron microscopy (SEM) are applied. Experimental findings revealed that the addition of fly ash (FA) enhances CS with curing time as an outcome of pozzolanic action. CS for 20% FA reinforcement after curing for 28 days was 42.95 MPa, compared with 41.53 MPa for 50%. This indicates that a higher addition of FA lowers CS. The rheological findings revealed that FA enhanced the viscosity of the cement slurry. The SEM images demonstrated that the incorporation of CFFA with cement modified the contexture of hardened cement. Cement, water, oilwell cement (OWC), curing time, dispersant, and FA were assigned as input variables for GMDH-LM while CS from the experimental analysis was set as output. Machine learning (ML) findings indicated that GMDH-LM can effectively estimate the CS of OWC. GMDH-LM performed better than backpropagation neural network (BPNN), support vector machine (SVM), and normal GMDH models in predicting CS; it provided higher linearity during training as GMDH-LM gave R2 = 0.958, GMDH = 0.946, SVM = 0.925, BPNN = 0.897, and the least loss functions of mean square error (MSE) = 0.238, MSE = 1.685, MSE = 2.567, and MSE = 4.032, respectively. Similarly, good results were ascertained during testing GMDH-LM provided R2 = 0.928, GMDH = 0.907, SVM = 0.895, BPNN = 0.878, and the lowest loss functions of MSE = 0.304, MSE = 2.650, MSE = 3.494, and MSE = 5.678, respectively. Therefore, the comparative results of all experiments and predictions reveal that GMDH-LM can be deployed as an advanced approach for the estimation of cement hydration in oil and gas wells.

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