The key in unlocking unconventional reserves is to create massive fracture surface area. During the fracturing treatment, a huge volume of fracturing fluid is pumped to generate fractures and then followed with a large amount of proppant to provide enough conductivity for reservoir fluid to flow to the wellbore. The ultimate proppant distribution in the fracture system directly impacts well productivity and production decline rate. However, it is very challenging to predict how far proppants can go and where they will settle because of the complexity of the fracture system. Therefore, accurate modeling of proppant transport inside the fracture system is critical to enable stimulation optimization. Previous modeling and experimental studies were usually based on simple proppant settling velocity models and limited only to planar fracture cases. To accurately evaluate propped complex fracture systems, which are more common in unconventional reservoirs, advanced proppant transport models are required.In this paper, proppant transport in various fracture geometries is investigated using computational fluid dynamics (CFD) models, in which the interaction between proppant particles and the carrying fluid phase is fully coupled to track proppant movement in the fractures. The planar fracture case is first investigated using a CFD model and benchmarked with results from commercial software. The CFD models are then used to simulate the proppant transport in T-junction and crossing-junction scenarios, which are often seen in unconventional reservoir fracture systems. Parametrical studies are also conducted to better understand how proppant transport is affected by fracture fluid viscosity, proppant density, and fluid injection rates.The results from the proposed CFD models indicate that proppant transport within complex fracture geometries is significantly affected by fracture fluid dynamics and proppant properties. At fracture junctions, turbulent flow regime will develop, which helps proppant propagate to natural fractures. According to the parametrical studies, higher injection rate and light-weight proppant are beneficial in transporting proppant through fracture junctions to reach further in both hydraulic fractures and natural fractures.Proppant transport models developed in this work fully incorporate the interaction between proppant particles and carrying fluid dynamics. This study extends the current understanding of proppant movement in complex fracture geometries and helps optimize hydraulic fracturing design to improve unconventional well production performance.

Recovery of frac-pack fluids is often poor in offshore operations. Large amounts of stimulation fluids left in the fracture may leak-off into the porous formation or block part of the proppant pack thus impairing hydrocarbon production. A typical frac-pack treatment fluid contains water-wetting surfactants to maximize flow-back fluids. However, the amounts recovered are still low and new methods are needed to improve well cleanup. Using a proppant that is neither oil nor water wet has the potential to solve some of these issues. Proppant surfaces were permanently modified to a neutral wettability state. Molecules having both hydrophobic and oleophobic properties were covalently bonded to the oxide surfaces, leading to robust engineered interfaces with low surface energy thus potentially improving flow. To support this concept of neutral wettability proppant, laboratory studies were conducted to determine performance under flow and cleanup ability compared to native proppant surfaces. This neutral wettability proppant was also used in several completions in the Gulf of Mexico. Two case histories using the neutral wettability proppant are presented and compared with offset wells as well as performance laboratory data. Flowback data as well as production data are reported. Laboratory results showed that the neutral wettability enhanced surfaces not only reduce water saturation but also improve oil movement. This demonstrates the ability of these materials to improve clean up and hydrocarbon flow within the proppant pack. When this proppant was applied in frac-pack completions it was observed that flow-back recovery was dramatically increased compared to offset wells that used similar proppant. Cleanup time was reduced allowing first oil to appear more rapidly. Furthermore, production data show that oil flow that the productivity index is higher when the surface of the proppant is neutral. These results demonstrate this material as next generation proppant for improving flow and cleanup in frac-pack completions.

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We have developed a fine-scale model of the sandstone core acid flooding process by solving acid and mineral balance equations for a fully three-dimensional flow field that changed as acidizing proceeded. The initial porosity and mineralogy field could be generated in a correlated manner in three dimensions; thus, a laminated sandstone could be simulated. The model has been used to simulate sandstone acidizing coreflood conditions, with a 1in.diam by 2in. long core represented by 8000 grid blocks, each having different initial properties. Results from this model show that the presence of small-scale heterogeneities in a sandstone has a dramatic impact on the acidizing process. Flow field heterogeneities cause acid to penetrate much farther into the formation than would occur if the rock were homogeneous, as is assumed by standard models. When the porosity was randomly distributed (sampled from a normal distribution), the acid penetrated up to twice as fast as in the homogeneous case. When the porosity field is highly correlated in the axial direction, which represents a laminated structure, acid penetrates very rapidly into the matrix along the high-permeability streaks, reaching the end of the simulated core as much as 17 times faster than for a homogeneous case.

Drilling long horizontal wellbores and completing wells using multistage fracturing are common practices in shale play development. One of the keys to enhancing production of these ultratight reservoirs is creation of a complex fracture system with very high surface area. Bi-wing fracture geometry parameters (length, height, width, and conductivity), are not sufficiently detailed to describe complex fractures. Instead, fracture density, unpropped and propped fracture conductivity, and stimulated reservoir volume (SRV) may be more appropriate parameters to consider in both fracture design and production modeling. Characterizing these parameters is challenging due to the uncertainty of natural fracture distribution, local stress changes, and the lack of granular reservoir description in three dimensions. Results of the current study show that post-treatment production data exhibit distinct features associated with various fracture systems and should be able to aid in describing the complex fracture system. The primary objective of this work was to find correlations between early-time production signatures and the fracture network. First, production simulation models were set up with various combinations of secondary fracture distribution, primary fracture conductivity, and different sizes of SRV. Those models were used to generate synthetic production and load recovery data for different scenarios. Secondly, the generated production data were analyzed with diagnostic plots to identify characteristic features for different fracture scenarios. Peak production, earlier production decline rate, and time to reach peak production were also evaluated and correlated to various fracture geometries. Results indicated that peak production correlated well with both SRV and secondary fracture density. Early-time decline rate was affected significantly by secondary fracture density. Time to reach peak production is impacted by fracture density, unpropped and propped fracture conductivity, and SRV. Diagnostic plots showed interesting features for various fracture scenarios, which may indicate complex flow regimes. This result needs further investigation. Introduction Although gas production from shales started a century ago, cost-effectively development of shale gas plays has always been a huge challenge in the gas industry. Shale gas reservoirs have ultralow permeability, usually on the order of 10s to 100s of nanodarcies. Conventional well completion techniques are not sufficient to achieve commercial production from such tight reservoirs. The two technologies that enable economic production of shale gas are long-lateral horizontal well drilling and multistage hydraulic fracturing. These technologies combine to create huge reservoir contact surface area by placing multiple transverse hydraulic fractures along long horizontal laterals. Hydraulic fracturing has long been an effective technique for stimulating low-permeability reservoirs. To simplify fracture modeling, biwing, single-planar fracture geometry was often assumed from prefracture design to postfracturing evaluation. However, fractures in the real world have been documented to be much more complex. Especially for economic shale plays, hydraulic fracture interaction with natural fractures may result in complex fracture network development. The biwing fracture parameters—length, height, width, and conductivity—are not sufficiently detailed to describe complex fractures. Instead, another set of parameters—fracture density, unpropped and propped fracture conductivity, and stimulated reservoir volume (SRV)—may be more appropriate parameters to consider in both fracture design and production modeling.