Optimization of Fracturing Fluid and Retarded Acid for Stimulating Tight Naturally Fractured Bedrock Reservoirs.

In tight naturally fractured bedrock reservoirs, hydrocarbons are typically stored in fractures, where hydraulic fracturing is needed to connect these fractures to the wellbore. The cross-linked gel is used as the fracturing fluid to reduce the fluid leak-off through natural fractures; however, it can cause formation damage due to its high content of residues after breaking. A synthetic polymer is introduced and evaluated that can maintain a high viscosity to minimize the leak-off , while having a low residue content after breaking. To further enhance the conductivity of the created fracture network, acid is applied to etch and roughen the created fracture faces. Because the target reservoir has a complex mineral composition, a three-step coreflood sequence using reservoir rock samples with controlled fracture widths is established to quantify the enhancement of different retarded acids and to reveal the mechanism behind it. The results indicate the synergy effect of reducing the acid concentration and surfactant adsorption on rock surfaces can lead to an obvious enhancement of the fracture permeability after acidizing, while the mud acid or hydrofluoric acid is not suitable for the target reservoir where concentrations of silicates and clays are relatively high.

Impacts of Proppant Flowback on Fracture Conductivity in Different Fracturing Fluids and Flowback Conditions.

Multistage hydraulic fracturing is used in horizontal wells to increase the production of tight oil. Fracturing fluids are used in hydraulic fracturing to ensure proppants are suspended, but fluid residuals can cause formation damage and reduce rock permeability; meanwhile, fracture conductivity can be further reduced due to the flowback of proppants during the early stage of production. In this study, steel plates and hydraulically fractured reservoir rocks are tested in a modified API cell to understand the impacts of flowback rate, fracturing fluid, and closure stress on proppant flowback and fracture conductivity. When the closure stress increased from 21 to 30 MPa, retained permeability decreased by slickwater from 35.71 to 29.84% in steel plates; during the flowback, more than 47% of proppants flowed back, and the fracture conductivity increased by 10 times under 21 MPa, which shows the limitation of the API method on the study of proppant flowback. When shale plates are used, the critical flow rate that prevents the proppant flowback was found to be 5.5 × 10-4-1.6 × 10-3 m/s for the 30/50 mesh sands (around 55-340 m3/d for a typical horizontal well), and the retained permeability decreased from 23.33 to 22.86% due to an increase of closure stress from 21 to 30 MPa. Results of this study can guide the optimizing of the flowback scheme in the field that minimizes the proppant flowback in different fracturing fluids.

Optimization and Evaluation of Stabilizers for Tight Water-Sensitive Conglomerate Reservoirs.

The upper Wuerhe formation in the Mahu-1 play is a tight conglomerate reservoir that has characteristics of low porosity and low permeability. During the early stage of field development, it has been noticed that horizontal wells typically have a high flowback ratio and an extremely low oil production rate during the early production, and this is likely attributed to the water-rock interaction that causes the closure of generated hydraulic fractures. In this study, a stabilizer and its dosage in a fracturing fluid are optimized, and its effect on clay antiswelling and rock stabilization is evaluated. Experimental results indicate that a mixture of a salt and an inorganic cationic polymer can effectively inhibit the water-rock reaction by minimizing the clay swelling and compressing the electric double layer on the rock surface. The antiswelling rate of montmorillonite can reach 93.56%, and that of the reservoir rock powder can reach 75.32%. Meanwhile, Brazilian splitting tests are conducted to evaluate the mechanical property change of reservoir rocks before and after being submerged in fracturing fluids with different stabilizers. Compared to 4% KCl, which is currently used in the field, the new formula can enhance the breakdown pressure by more than 10% without increasing the cost. The findings of this work provide a solution for fracturing water-sensitive reservoirs and also establish a set of laboratory methods for optimizing stabilizers as fracturing fluid additives.

Field experiments of different fracturing designs in tight conglomerate oil reservoirs.

Mahu oilfield is currently the largest tight conglomerate reservoir in the world, where Ma-131 and Ma-18 plays are the first two commercially developed reservoirs. In order to reduce the cost and explore the best fracturing parameters, field experiments have been conducted in these two plays since 2017. Types of proppant and fracturing fluid, the slickwater ratio, and the fracture spacing are mainly changed for comparison, and fracturing effects are evaluated to establish a reference for developing neighboring plays in the Mahu oilfield. This paper summarizes the fracturing parameters and production histories of 74 wells in Ma-131 and Ma-18 plays during four years of field operations. Firstly, results indicate that silica sands perform similar to ceramics in the Ma-131 play where the reservoir depth is smaller than 3300 m; however, in the Ma-18 play where the reservoir is deeper than 3500 m, increasing the sand volume by 1.1-1.2 times still cannot reach the production in wells using ceramics. Secondly, when the fracture spacing is reduced, both oil production and water flowback become even smaller in wells using sands than those using ceramics; this is due to the increase of closure pressure and decrease of fluid volume per cluster respectively. Thirdly, when the crosslinked guar is replaced by the slickwater, no obvious change in oil production is noticed even though the volume of fracturing fluid is almost doubled; limited lengths of propped fractures due to the poor proppant-carrying ability of slickwater likely offset the production enhancement from the decrease of formation damage by slickwater. This paper summarizes learnings from the field experiments during the four-year development of the Mahu oilfield, and help guide the optimization of hydraulic fracturing parameters for future wells.

Micromodel Studies of Surfactant Flooding for Enhanced Oil Recovery: A Review.

Micromodels have been widely used to visualize surfactant flooding, which provides new insights into understanding pore-scale events during displacement. In this review, recent advances in micromodel studies of surfactant flooding are briefly summarized. The mechanisms of surfactant flooding as demonstrated by micromodel studies are presented, as well as pore-scale findings that cannot be captured by traditional coreflood methods.

A New Intermittent Pumping Design for Fluid Shortage Wells.

Low oil price requires oil companies to reduce costs and increase benefits. The wells with deficient fluid supplies approximately account for 20-30% of all producing wells, and this situation is even worse in the old oilfields. Intermittent production is an effective way to reduce the cost and increase the system efficiency to overcome the shortage of oil supply from the reservoir. The key is to optimize the intermittent pumping scheme, i.e., to design reasonable shut-in and operating periods. In this study, this is achieved using the dynamic change of the fluid level in the wellbore. From the electrical power curve to the dynamometer card, the dynamic drop of the fluid level can be obtained, and thus the optimal operation time of the well; at last, from the inflow performance of the well, the optimal shut-in period can be obtained. This method shows a good application in the field through a case study.

A 2.5-D glass micromodel for investigation of multi-phase flow in porous media.

We developed a novel method for fabrication of glass micromodels with varying depth (2.5-D) with no additional complexity over the 2-D micromodels' fabrication. Compared to a 2-D micromodel, the 2.5-D micromodel can better represent the 3-D features of multi-phase flow in real porous media, as demonstrated in this paper with three different examples. Physically realistic capillary snap-off and the formation of isolated residual oil droplets were realized, which is not possible in 2-D micromodels. Droplet size variation during an emulsion flooding was investigated on the 2.5-D micromodel, showing that the droplet size decreases sharply at the inlet, with little change in size downstream of the micromodel. Displacement of light oil with ultra-low interfacial tension (IFT) surfactant was conducted in the 2.5-D micromodel, where we were able to visualize the generation and flowing of a microemulsion phase, which agrees with, and explains observations in experiments of more complex porous media.