Proving the Concept of Unconventional Gas Reservoirs in Saudi Through Multistage Fractured Horizontal Wells

Almomin, Ali; Kurdi, Mohammed; Baki, Sohrat; Mechkak, Karim; Al-Saihati, Ali

doi:10.2118/174754-ms

Cited by 13 publications

(2 citation statements)

References 1 publication

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“…Samples taken from TWQ core show the presence of abundant micro-fractures and natural fractures, which will support production when hydraulic fracture stimulation treatment operations are applied to all wells. Early production data were given in Al-Momin et al [32]. However, it is not entirely correct to assume high initial flow rates are due to linear flow from fluid stored in fracture systems.…”

Section: Natural Fractures and Permeabilitymentioning

confidence: 99%

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Workflow for Probabilistic Resource Estimation: Jafurah Basin Case Study (Saudi Arabia)

2021

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This study provides a workflow and preliminary estimations of the estimated ultimate recovery (EUR) volumes for natural gas and condensate liquids in the Tuwaiq Mountain Formation, the principal target in the Jafurah Field development project in Saudi Arabia. The strategic need for the field development is reviewed and the field characteristics are outlined based on public data sources complemented with data from analogous reservoirs. The target zone in the Jafurah Basin is a carbonaceous shale, being developed with up to 10,000-ft-long multistage-fractured laterals with 30 ft perforation cluster spacing and an assumed typical 1250 ft well spacing. The field will come on stream in 2024, when the gas-gathering pipeline system, natural gas processing plant, and underground gas storage facilities will all be in place. The range of uncertainties in the key reservoir parameters is taken into account to estimate preliminary EUR volumes (P90, P50, and P10) for both gas and condensates. Based on the present and prior EUR estimations, it can be concluded that the Jafurah Basin comprises one of the largest unconventional field development projects outside of North America.

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Section: Natural Fractures and Permeabilitymentioning

confidence: 99%

“…The total vertical depth (TVD) is 6500 ft, with a total well length of 10,000 ft, indicating a 3500 ft lateral. The local stress field is characterized by strike-slip conditions, with Sv = 1.1 psi/ft, SH_max = 1.2 psi/ft, and Sh_min = 0.96 psi/ft [32].…”

Section: Tectonic Closure Pressure and Fluid Overpressurementioning

confidence: 99%

Workflow for Probabilistic Resource Estimation: Jafurah Basin Case Study (Saudi Arabia)

2021

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Computational Fluid Dynamics Applied To Investigate Development of Highly Conductive Channels Within the Fracture Geometry

Gomaa

Hudson

Nelson

et al. 2017

SPE Production &Amp; Operations

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Summary A conventional proppant pack may lose up to 99% of its conductivity because of gel damage, fines migration, multiphase flow, and non-Darcy flow. Therefore, the concept of pillar fracturing was developed to generate highly conductive paths for hydrocarbon to flow. This paper describes experimental results and numerical models of a new method to generate stable proppant pillars. The proposed treatment method depends on fingering phenomena observed when a less-viscous fluid that does not carry proppant is injected to displace a more-viscous one that carries proppant. Because the low-viscosity fluid tends to move faster than the high-viscosity fluid, the low-viscosity fluid can penetrate the high-viscosity fluid and create channels inside it. This reshapes and divides the proppant-laden, high-viscosity fluid into isolated patterns that create proppant pillars. Large-scale experiments (slot test, 2-ft height and 16-ft length) were performed to evaluate the development and stability of the created channels by use of different injection rates and different fluid viscosities. In addition, a computational fluid dynamics (CFD) model was constructed to simulate the experiment results and to scale them up into full fracture dimensions. The study focused on the effects of surface-injection rate [1 to 40 (bbl/min)/cluster], pulsing time (5 to 60 seconds), and viscosity ratio (from 2 to 200) between the two injected fluids. Experimental results and numerical modeling showed that with the use of viscous-fingering phenomena, a pillar-propped fracture with conductive and stable channels can be created. Channel shape and size were dependent on injection rate where increasing the injection rate reduces the main channel width with increasing the channel branching. Full piston-displacement behavior was noticed after 60% of the fracture height, when a high-viscosity fluid displaced a low-viscosity fluid, and their viscosity ratio was greater than 5. By reducing the viscosity ratio between the two fluids, the created channel shape converts from cylindrical (where the beginning and end of the channel have the same width) to conical behavior (where the beginning of the channel is wider than the end). This explains why the length of the channel decreases with the viscosity ratio between the two fluids. Distance between pillars was reduced with increasing travel distance from the wellbore, or with reduced pulse-stage volume, time, or rate.

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Completion Quality Classes to Characterize Basin Complexity: New Framework to Incorporate Localized and Regional Reservoir Heterogeneity into Field Exploration and Development Optimization

Gurmen

Fredd

Batmaz

et al. 2016

SPE Annual Technical Conference and Exhibition

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Innovation and advances in technology have enabled the industry to exploit lower-permeability and more-complex reservoirs around the world. Approaches such as horizontal drilling and multistage hydraulic fracturing have expanded the envelope for economic viability. However, along with enabling economic viability in new basins come new challenges. Such is the case in the Middle East and North Africa regions, where basin complexity arising from tectonics and complicated geology is creating a difficult geomechanical environment that is impacting the success of hydraulic fracturing operations in tight reservoirs and unconventional resources. The impact has been significant, including the inability to initiate hydraulic fractures, fracture placement issues, fracture connectivity limitations, casing deformation problems, and production impairment challenges. Completion quality (CQ) relates to the ability to generate the required hydraulic fracture surface area and sustained fracture conductivity that will permit hydrocarbon flow from the formation to the wellbore at economic rates. It groups parameters related to the in-situ state of stress (including ordering, orientation, and amount of anisotropy), elastic properties (e.g., Young's modulus and Poisson's ratio), pore pressure, and the presence of natural fractures and faults. Collectively, this group of properties impacts many key aspects determining the geometry of the fracture, particularly lateral extent and vertical containment. Heterogeneity in CQ often necessitates customizing well placement and completion designs based on regional or local variability. This customization is particularly important to address local heterogeneity in the stress state and horizontal features in the rock fabric (e.g., laminations, weak interfaces, and natural fractures) that have been identified as key contributors impacting the success of hydraulic fracture treatments. Given the observation that a wide range of CQ heterogeneity was creating a complex impact on hydraulic fracture performance, CQ classes were introduced to characterize the risk of developing hydraulic fracture complexity in the horizontal plane and the associated impact on well delivery and production performance. They indicate the expected hydraulic fracture geometry at a given location and are analyzed in the context of a wellbore trajectory in a given local stress state. CQ class 1 denotes locations where conditions lead to the formation of vertical hydraulic fractures, CQ class 2 denotes locations where conditions lead to the formation of a T-shaped or twist/turn in the hydraulic fracture, and CQ class 3 denotes locations where conditions lead to the formation of hydraulic fracture with predominantly horizontal components. Wellbore measurements indicate that these CQ classes can vary along the length of the wellbore, and 3D geomechanical studies indicate that they can vary spatially across a basin. By understanding this variability in CQ class, well placement and completion design strategies can be optimized to overcome reservoirheterogeneity and enable successful hydraulic fracturing in more challenging environments. This paper introduces the novel concept of CQ class to characterize basin complexity; shows examples of CQ class variability from around the world; and provides integrated drilling, completion, and stimulation strategies to mitigate the risks to hydraulic fracturing operations and optimize production performance.

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Proving the Concept of Unconventional Gas Reservoirs in Saudi Through Multistage Fractured Horizontal Wells

Cited by 13 publications

References 1 publication

Workflow for Probabilistic Resource Estimation: Jafurah Basin Case Study (Saudi Arabia)

Workflow for Probabilistic Resource Estimation: Jafurah Basin Case Study (Saudi Arabia)

Computational Fluid Dynamics Applied To Investigate Development of Highly Conductive Channels Within the Fracture Geometry

Completion Quality Classes to Characterize Basin Complexity: New Framework to Incorporate Localized and Regional Reservoir Heterogeneity into Field Exploration and Development Optimization

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