Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.
Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves.
Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects.
This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.
Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during well drilling, completion, stimulation and production (Dusseault, 1993). The low permeability gas reservoirs can be subject to different damage mechanisms such as mechanical damage to formation rock, plugging of natural fractures by invasion of mud solid particles, permeability reduction around wellbore as a result of filtrate invasion, clay swelling, liquid phase trapping, etc (Holditch, 1979).
In general, for tight sand gas reservoirs, average pore throat radius might be very small and therefore it may create tremendous amounts of capillary forces. Capillary forces cause the spontaneous imbibition of a wetting liquid (in this case water) in the porous medium in the absence of external forces such as a hydraulic gradient (Bennion and Brent, 2005). This causes significantly high critical water saturation (Bennion et al., 2006). Two forces drive capillary flow (Adamson and Gast, 1997). The first is the reduction in the surface free energy by the wetting of the hydrophilic surface (wettability). In hydraulic fracturing, water in the fracturing fluid wets the surface of the pores in the rock, resulting in a decrease in the surface free energy of the pores. The other force that drives capillary flow is the capillary pressure.
Tight gas reservoirs might be different in term of initial water saturation (Swi) compared with critical water saturation (Swc), depending on the geological time of gas migration to the reservoir. Initial water saturation might be normal, or in some cases sub-normal (Swi less than Swc) due to water phase vaporization into the gas phase (Bennion and Thomas, 1996). The initial water saturation might also be more than Swc if the hydrocarbon trap is created during or after the gas migration time. A sub-normal initial water saturation in tight gas reservoirs can provide higher relative permeability for the gas phase (effective permeability close to absolute permeability), and therefore relatively higher well productivity (Bennion and Brent, 2005).
Exploitation of thin oil zones in a mature field with complex carbonate geology under strong water drive offers many challenges. The primary objective is effective oil recovery from the thin oil zones without excessive water production. The initial development phase targeting thin remaining oil zones in a giant, mature carbonate field in Saudi Arabia has been guided by reservoir simulation results, with performance generally exceeding expectations. However, performance of individual horizontal wells has varied greatly. Multivariate statistical methods have been applied across the gamut of reservoir parameters for these wells to gain further insights into critical success factors and mechanisms. Response variables were established (producing time to reach various watercut thresholds) to gauge well performance. Principal component, factor, and multiple regression analyses were applied to independent reservoir parameters for a population of 20 horizontal wells placed in the target zone. These parameters included zone thickness, standoff from fluid contacts, vertical permeability contrast, thickness of low-permeability interval, reservoir contact, net/gross ratio, completion design, extent of fracturing, zone porosity, proximity to injectors, and trajectory orientation. Multivariate analysis conclusively demonstrated that the principal factor governing well performance in the early period (up to three years) was the vertical permeability contrast or in other words, the extent to which a permeability baffle exists between the thin low-permeability zone and the underlying thick high-permeability zone. Other parameters may contribute to well performance beyond the 30% watercut threshold and will be addressed in a future paper. The findings from this study have been translated into Best Practices for exploiting thin oil zones and have been applied in further developing the thin oil zone in the subject field.