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Summary In well stimulation operations, the ability to sustain long-term conductivity of hydraulic/acid fractures defines an efficient and effective hydrocarbon production operation. However, it is challenging to keep the fracture conductive in the soft and weak carbonate formations due to many challenges. For example, the plastic deformation of rocks causes proppant embedment or asperities failure, resulting in fracture conductivity reduction. Consolidating chemicals, particularly diammonium hydrogen phosphate (DAP), have shown to be effective in rock consolidation and could reduce the decline in fracture conductivity if applied to carbonate formations. The previous research tested DAP at ambient conditions, whereas this work involves studying the hardening properties of DAP at reservoir conditions. The solutions with two initial concentrations (1 and 0.8 M) were tested at 77°F (ambient), 122°F, and 176°F. Furthermore, a post-treatment analysis was conducted to compare the performance of the chemical under different conditions. The analysis included understanding the changes in carbonate rocks’ (limestone and chalk) hardness (impulse hammer test and indentation test), porosity (helium porosimeter), permeability (steady-state and unsteady state nitrogen injection), and mineralogy [X-ray diffraction (XRD) and scanning electron microscopy (SEM)]. Results demonstrated that both rock lithologies reacted efficiently with the DAP solution, presented in terms of the noticeable improvements in their hardness. The elevated temperatures positively affected rock hardness, leading to a more than 100% increase in hardness for most samples. After obtaining successful results from experiments at various temperatures, the pilot American Petroleum Institute (API) conductivity experiments were conducted, testing the conductivity sustenance through the rock hardening concept. Preliminary API conductivity experiments have demonstrated that treated rock samples with DAP provided higher conductivity values than the untreated samples at high stresses. The results shown in this study provide a good foundation for further studies on the implementation of DAP in actual acid/hydraulic fracturing field operations.

Chemical consolidation of rocks is a common practice in the petroleum industry. Usually, this technique is applied to sustain production from unconsolidated or weak sandstone formations and to avoid collapse from aging wells. Recent research has shown the significance of rock hardness in sustaining long-term conductivity of hydraulic fractures in carbonate formations. There are some notable attempts to adapt the techniques used in the cultural heritage industry for strengthening carbonate formations. Moreover, a novel carbonate rock strengthening methodology was developed that involves the mineral transformation of calcite to harder minerals. This work describes the existing techniques for carbonate rock consolidation and provides extensive research on chemicals that are (or can be) used as carbonate rock strengthening agents. Furthermore, this review provides the reaction mechanisms associated with a range of proposed chemicals. Also, laboratory methods that can be used to assess post-treatment hardness and investigate the changes in rock mineralogy are summarized. Finally, the review discusses chemicals with the prospect of their application in petroleum field operations.

Upscaling of properties for reservoir simulation has reached a stage of maturity and uses sophisticated techniques. In contrast, little work has been done on upscaling of mechanical properties for coupled modeling, and the geomechanical model is usually assumed to be representative (upscaled) without actually being subjected to the same rigor of process or scrutiny. Compacting reservoirs often contain fine sand-shale sequences on sub-grid scale (compared to flow modeling grid) and are typically represented in simulators by the net-to-gross (NTG) concept, while being ignored in geomechanical modeling.In this work, we present a method to upscale shales in the geomechanical component of a coupled simulation by computing dynamically changing equivalent moduli. The method is based on estimating the depletion of interbedded shales, coupled with analytical solutions for equivalent moduli under the assumption of uniaxial deformation. The technique has been verified by sub-grid scale simulations and requires geometric characterization of the shales but is relatively simple and can be easily implemented in coupled simulators. The analysis shows that the inclusion of the shales generally reduces computed compaction, with the controlling variables being NTG, dimensionless pressure depletion of the shales (which in turn depends on their flow properties) and mechanical properties of the shales.The approach developed was incorporated in the subsidence and compaction analysis over a complex offshore oil reservoir. The reservoir zone consisted of a number of intervals that included relatively undeformed as well as highly deformed layers, and on reservoir model scale had significant NTG ratios. A comprehensive study (based on coupled flow and geomechanics simulation) was conducted to evaluate well integrity, fault slip (reactivation) and compaction drive. A large full field model was built using data from a multitude of sources and production data was modeled and history matched, allowing us to estimate the magnitude of reservoir subsidence and the contribution of the NTG effect on predictions. The study presented here showed that in the absence of any consideration of the NTG effect, predictions (for compaction and subsidence) could be significantly overestimated. In addition, the method can be used to study the phenomena of "time-lag" of subsidence which has been observed in some reservoirs.

An advanced wellbore stability analysis software product has been developed in-house at Aramco. This product offers three analysis modules: (1) the classical mechanical module (elastic); (2) the time-dependent analysis module (poroelasticity); and (3) the time-dependent analysis of naturally fractured rock module (dual-porosity and dual permeability poroelasticity). The stress and pressure analyses are integrated with four rock failure criteria (Mohr-Coulomb, Drucker-Prager, Modified Lade, and Hoek-Brown) to calculate critical mud densities. The basic mechanical module is similar to the wellbore stability module provided in the most-frequently-used drilling geomechanics software. What sets this product apart from the others is that no commercial drilling software to date has the time-dependent stress and pressure analyses modeled by this product's poroelastic and dual-porosity poroelastic modules, which can capture real-time phenomena introduced by the time-dependent fluid pore pressure perturbation and the wellbore time-dependent failures in tension and/or compression.