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Palencia Yrausquin, E. (China University of Petroleum / College of Petroleum Engineering) | Liu, W. (China University of Petroleum / College of Petroleum Engineering) | Zhou, B. (China University of Petroleum / College of Petroleum Engineering) | Kamgue Lenwoue, A. R. (China University of Petroleum / College of Petroleum Engineering)
ABSTRACT: Data Different hydraulic fracturing experiments were enhanced in unconsolidated sandstones to investigate the fundamental mechanisms controlling fracture propagation, and the published observations consider that the efficiency of the fracture initiation and growth on unconsolidated sandstones is about the injection rate, rheology of the fracture fluid, confining pressure, and the principal mechanism of propagation is shear failure. Because of that, in this research, a reference between laboratory studies and numerical simulation are conducted to delineate the influence of the mechanical properties in mechanism of failure on the fracture propagation in unconsolidated sandstones. The samples were prepared with different scales of quartz sand, illite, montmorillonite, and water were mixed according to the depth of typical unconsolidated sandstone reservoirs in the Bohai-China; the size of the samples is 100 mmxmm, while the permeability of the samples is either about 1000 mD. In this way, the injection of a polymer until saturation of the core sample was applied until it gave an accurate result on the mechanical properties, changing to UCS to unconsolidated sandstones 1.6 mPa, at 3.9 mPa to enhanced sandstones with resin, improving the propagation of the fracture and leading to study the mode of failure, the initiation, and extension of the fracture on this type of sandstones. The experimental results showed that the samples without resin were completely saturated by the fracturing fluid without evidence of fracture, while for unconsolidated sandstones with resin injection ratio 2:3, generated quasi-planar, single wing fractures when using a low flow rate, and high viscosity of the fracturing fluid, and branching fractures for high flow rate and high viscosity fluid; the principal mechanism of failure was shear failure and shear-enhanced failure into the radius of consolidation of the core samples, showing control in the direction of the fractures in a circular area of 14-18 mm, on the near-wellbore region. This research can provide that the mechanical properties as a function of the fluid leakoff can determine the orientation and propagation of the fracture, even when the unconsolidated sandstones were enhanced by chemical injection with a low injection rate, the fracture propagation just stopped when is crossing the radio of the enhanced unconsolidated sandstone, it is desired to provide greater knowledge to the mechanism of failure in unconsolidated reservoirs.
Olaoye, Olubiyi (Sanjel) | Durkoop, Charles (Vermillion Energy) | Johnson, Reed (Vermillion Energy) | Anderson, Daniel (Vermillion Energy) | Cherian, Bilu V (Sanjel) | Kublik, Kristina (Sanjel) | Narasimhan, Santhosh (Sanjel) | Atkinson, Mariah (Sanjel) | Shaikh, Hamza (Sanjel) | Gray, James (Sanjel) | Rifai, Rafif (Sanjel)
Abstract The North American unconventional resources energy growth driven by the combination of horizontal drilling, completion tools and hydraulic fracturing innovations has revitalized some conventional plays across the globe that were considered marginal prior to the unconventional boom. This paper presents the workflows utilized to implement unconventional technologies that have resulted in incremental hydrocarbon resources being unlocked. A multi-domain approach is utilized to understand the results from the application of horizontal drilling, completion tools and hydraulic fracturing innovations to the Turner play. High tier log and core data is used initially to create petrophysical and geomechanical models. Numerous petrophysical and geomechanical models are generated based on the uncertainty in model building. Appropriate models are selected based on fracture pressure matching and production history matching techniques. These models are then used to drive the design and optimization process of future offset wells. Characterization of the reservoir (permeability range, pressure and fluid saturations) has led to the understanding that completion techniques used in unconventional plays (slickwater fluid system with tight cluster spacing) cannot be blindly applied. An understanding of fracture geometry and reservoir quality enables changes to be implemented on lateral landing, stage count and job size resulting in incremental production. The importance of reservoir characterization and forward modeling of the application of horizontal technologies is crucial to ensuring efficient allocation of resources to maximize production. This paper showcases the application and evolution of unconventional technologies and workflows to conventional plays to gain incremental production results.
The objective of this paper is to review the hydrofracturing experience in one of the Omani oil fields and to provide better understanding of geological and operational controls on the productivity of the fractured wells.
The methodology adopted in the study relied on the geomechanical evaluation for understanding the hydrofracture geometry. In particular a geomechanical model was built and calibrated by history matching the simulated and field data. Further, the implications of the created hydrofracture geometry in productivity have been studied based on the conceptual understanding and actual production histories. Last but not least, the influence of operational parameters on the hydrofracture success has also been studied.
The geomechanical evaluation concluded that it is likely that the hydraulic fracture’s growth is unconfined and downwards. Because of the combination of the unconstrained growth with relatively high reservoir permeability, the created fractures potentially are of limited length and of relatively good conductivity. According to a semi-analytical bi-linear production model, these parameters are nearly optimal for the particular reservoir. Preference for highly conductive and short fracture is due to reazonably high fluid mobility in the reservoir, high viscosity of hydrocarbons, and a relatively close well spacing. Horizontal well technology is an alternative to the hydraulic fracturing in the considered settings. Meanwhile the preference may be given to hydraulic fracturing if the commingling of the targeted unit with the overlying or underlying reservoirs is sought after. On the other hand, in the areas of structural deep, the unconfined downward growth poses a risk of connecting to the water zone. Production histories of the wells indicate that water inflow has a very pronounced negative effect on hydrocarbon production and thus must be avoided. The calibrated geomechanical model helps in choosing operational parameters that allow for proper hydrofracture design in the areas of structural deep. Nevertheless, horizontal wells will be beneficial in the areas where fracture connectivity to the water zone is likely.
Finally, a review of the fracturing operations has been carried out to understand the potential for improving the success rate. Because of the overall limited number of hydrofracturing jobs in the field, the results are far from being definitive. Meanwhile it is possible to hypothesize on the range of optimal operational parameters. In particular, this study recommends using limited volumes of fracturing fluids and coarser proppant mesh. The choice is based on the necessity to avoid communication with the water zone and the requirement of a highly conductive fracture for the efficient drainage. The recommendation is supported by limited trials. A viable alternative is combining deviated drilling technology with hydraulic fracturing. In such combination longitudinal small volume fractures should be targeted. The benefits of production enhancement and potentially achieving better capital efficiency are then achieved through commingling production from several units and increasing wellbore connectivity with the reservoirs.
Meanwhile, it is important to keep in mind that the economic benefits can be realized when applying each of the considered development options, i.e., i) vertical, or ii) deviated commingled fractured wells, or dedicated horizontal non-fractured wells. In the considered field the particular choice is driven by the current economic environment, thorough risk assessment, and operational efficiency.
Razavi, Omid (The University of Texas at Austin) | Vajargah, Ali Karimi (The University of Texas at Austin) | van Oort, Eric (The University of Texas at Austin) | Aldin, Munir (Metarock Laboratories) | Patterson, Robert (Metarock Laboratories)
Abstract Wellbore strengthening (WBS) offers enabling technology for wells that are drilled in geological environments with a narrow drilling margin. Through its deployment, costly lost circulation events may be avoided, casing setting depths may be extended, and, in optimum cases, deeper targets may be reached with a reduced or slimmed-down casing program. The elevation of the fracture gradient offered by WBS is a complex issue that involves the growth of fractures in permeable or impermeable rocks using non-Newtonian drilling fluids that are laden with solids of varying types and sizes. Several plausible (and sometimes contradictory) models have been proposed historically to explain the WBS phenomenon, and the only way to assess the correct explanation is through dedicated experimentation. In this paper, an experimental technique to study WBS under realistic conditions is introduced, and the results of a series of larger-scale fracturing experiments using this technique are presented. The experimental set-up described here consists of a dual flow-loop/ pressure-intensifying system to carry out high-pressure borehole fracturing tests on cylindrical rock samples while maintaining continuous circulation of the drilling fluid within the borehole. The system offers full control over pore pressure, radial confining pressure and, if desired, independent axial pressure. Several injection cycles are performed to characterize the values of the fracture initiation pressure (FIP) and fracture propagation pressure (FPP) and thereby characterize WBS effects. Typical experimental variables included: the type of base fluid (water-based, oil- or synthetic-based), the concentration, type, and particle size distribution (PSD) of lost circulation materials (LCMs) used to achieve WBS effects, and the type of rock tested (sandstone and shale, i.e. permeable and impermeable rock media). Additionally, post-fracturing techniques such as thin-section analysis were employed to study the fracture geometry and deposition structure of plugging solids on the fracture surfaces. The experiments clearly show that for any rock with a given set of rock strength and failure parameters, there is an optimum PSD for maximizing WBS effects. Optimum PSD appears to be of primary importance, almost irrespective of LCM type. The results furthermore show that although a minimum concentration of LCM bridging agents is required for effective WBS, FPP does not increase significantly for concentrations above a certain upper threshold value. Moreover, increasing the injection volume during WBS squeeze treatments above a threshold value may actually lead to lower FPP values. All of these findings have important implications for field application of WBS treatments. In addition, petrographic imaging of the fracture after testing show that fracture plugging occurs in the proximity of the fracture tip and not close to wellbore face, in direct support of the Fracture Propagation Resistance (FPR) model of WBS, and in disagreement with Wellbore Stress Augmentation/ Stress Cage models. The results not only confirm information from previous investigations, but also provide new insight into effective ways to strengthen wellbores in various formations. The experimental results are directly applicable to improve well construction and to minimize non-productive time on narrow drilling-margin wells such as (ultra-) deep-water wells by selecting the appropriate mud formulations, LCM materials and their concentrations, as well as application treatments.