Multiphysics coupling study of near-wellbore and reservoir models in ultra-deep natural gas reservoirs

Understanding the changes of the near-wellbore pore pressure associated with the reservoir depletion is greatly significant for the development of ultra-deep natural gas reservoirs. However, there is still a great challenge for the fluid flow and geomechanics in the reservoir depletion. In this study, a fully coupled model was developed to simulate the near-wellbore and reservoir physics caused by pore pressure in ultra-deep natural gas reservoirs. The stress-dependent porosity and permeability models as well as geomechanics deformation induced by pore pressure were considered in this model, and the COMSOL Multiphysics was used to implement and solve the problem. The numerical model was validated by the reservoir depletion from Dabei gas field in China, and the effects of reservoir properties and production parameters on gas production, near-wellbore pore pressure and permeability evolution were discussed. The results show that the gas production rate increases nonlinearly with the increase in porosity, permeability and Young’s modulus. The lower reservoir porosity will result in the greater near-wellbore pore pressure and the larger rock deformation. The permeability changes have little effect on geomechanics deformation while it affects greatly the gas production rate in the reservoir depletion. With the increase in the gas production rate, the near-wellbore pore pressure and permeability decrease rapidly and tend to balance with time. The reservoir rocks with higher deformation capacity will cause the greater near-wellbore pore pressure.

A Play-Wide Performance Review of Plug and Perf, Ball and Seat, and Pinpoint Fracturing Methods in the Montney Tight Siltstone Reservoir

The Montney reservoir is one of the most prolific unconventional multi-stacked dry and liquid-rich gas plays in North America. The type of fracturing method and fluid has a significant impact on water-phase trapping, casing deformation, and well performance in the Montney. Different fracturing methods (plug and perf/plug and perf with ball/ball and seat/single-entry pinpoint) and fluids (slickwater/hybrid/oil-based/energized/foam) have been tested in 4000+ Montney wells to find optimal fracturing method and fluid for different reservoir qualities and fluid windows and to minimize water-phase trapping and casing deformation. The previous studies reviewing the performance of fracturing methods in Montney do not represent a holistic evaluation of these methods, due to some limitations, including: (1) Using a small sample size, (2) Having a limited scope by focusing on a specific aspect of fracturing (method/fluid), (3) Relying on data analytics approaches that offer limited subsurface insight, and (4) Generating misleading results (e.g., on optimum fracturing method/fluid) through using disparate data that are unstructured and untrustworthy due to significant regional variation in true vertical depth (TVD), geological properties, fluid windows, completed lateral length, fracturing method/fluid/date, and drawdown rate management strategy. The present study eliminates these limitations by rigorously clustering the 4000+ Montney wells based on the TVD, geological properties, fluid window, completed lateral length, fracturing method/fluid/date, and drawdown strategy. This clustering technique allows for isolating the effect of each fracturing method by comparing each well's production (normalized by proppant tonnage, fluid volume, and completed length) to that of its offsets that use different fracturing methods but possess similar geology and fluid window. With similar TVD and fracturing fluid/date, wells completed with pinpoint fracturing outperform their offsets completed with ball and seat and plug and perf fracturing. However, wells completed with ball and seat and plug and perf methods that outperform their offset pinpoint wells have either: (1) Been fractured 1 to 4 years earlier than pinpoint wells and/or (2) Used energized oil-based fluid, hybrid fluid, and energized slickwater versus slickwater used in pinpoint offsets, suggesting that the water-phase trapping is more severe in these pinpoint wells due to the use of slickwater. Previous studies often favored one specific fracturing method or fluid without highlighting these complex interplays between the type of fracturing method/fluid, completion date (regional depletion), and the reservoir properties and hydrodynamics. This clustering technique shows how proper data structuring in disparate datasets containing thousands of wells with significant variations in geological properties, fluid windows, fracturing method/fluid, regional depletion, and drawdown strategy permits a consistent well performance comparison across a play by isolating the impact of any given parameter (e.g., fracturing methods, depletion) that is deemed more crucial to fracturing design and field development planning.

Finding the Best of the Best: Hydraulic Fracturing Design Optimization Study in Oman

Development of the tight gas Khazzan Field in Sultanate of Oman has progressed through an extensive learning curve over many years. Thereby, the hydraulic fracturing design was fine-tuned and optimized to properly fit the requirements of the challenging Barik reservoir in this area. In 2018, BP Oman started developing the Barik reservoir in the Ghazeer Field, which naturally extends the reservoir boundary south of Khazzan Field. However, the Barik reservoir in the Ghazeer area is thicker and more permeable than in the Khazzan Field; therefore, the hydraulic fracturing design required adjustment to be optimized to directly reflect the reservoir needs of the Ghazeer Field. A comprehensive hydraulic fracturing design software was used for this optimization study and sensitivity analysis. This software is a plug-in to a benchmark exploration and production software platform and provides a complete fracturing optimization loop from hydraulic fracturing design sensitivity modelled with a calibrated mechanical earth model to detailed production prediction using the incorporated reservoir simulator. One of the stimulated wells from Ghazeer Field was used as the reference for this study. The reservoir sector model was created and adjusted to match actual data from this well. The data include fracturing treatment execution response, surveillance data such as radioactive tracers, bottomhole pressure gauge, and pressure transient analysis. Reservoir properties were also adjusted to match long-term production data obtained for this reference well. After the reservoir model was fully validated against actual data, multiple completion and fracturing scenarios were simulated to estimate potential production gain and thus find an optimal hydraulic fracturing design for Ghazeer Field. Many valuable outcomes can be concluded from this study. The optimal treatment design was identified. The value of fracture half-length versus conductivity was clarified for this area. The comparison between single-stage fracturing versus multistage treatment across the thick laminated Barik reservoir in a conventional vertical well was derived. The drainage of different layers with variable reservoir properties was compared for a range of different scenarios.

Quantifying occurrence of deformation bands in sandstone as a function of structural and petrophysical factors and their impact on reservoir quality: an example from outcrop analog of Productive Series (Pliocene), South Caspian Basin

Deformation bands (DB) are known to influence porosity and permeability in sandstones. This study aims to predict the occurrence of DB and to quantify their impact on reservoir properties based on field measurements in the steeply dipping limb of a kilometer-scale fold in Yasamal Valley, western South Caspian Basin. An integrated approach of characterizing bands and their effect on reservoir properties included measurements of natural gamma radioactivity and permeability using portable tools, along with bed dip and the count of DB across distinct facies. A set of core analyses was performed on outcrop plugs with and without bands to estimate the alteration of rock properties at the pore scale. Interpretation of outcrop gamma-ray data indicates the absence of bands in Balakhany sandstones containing shale volume greater than 18% for unconsolidated and 32% for calcite-rich facies. A high amount of calcite cement appears to increase the number of DB. A poor, positive trend between bed dip and DB concentration was identified. We show that net to gross, defined as the thickness fraction of sandstone bound by mudstones, is among the parameters controlling the occurrence of bands. Samples containing a single DB show a 33% and 3% decrease in permeability and porosity, respectively, relative to the host rock. We reveal a new set of lithological and petrophysical factors influencing DB occurrence. This study offers a direct tool that can be applied in subsurface reservoir analogs to predict the occurrence and concentration of DB and estimate their influence on rock properties.