Innovative Techniques for Optimization of Far-Field Diverter Materials to Enhance Fracture Geometry in Carbonate Reservoirs

2021 ◽  
Author(s):  
Maunish Shah ◽  
Nicholas A. Koster ◽  
Connor Clark ◽  
Subhash N. Shah
Keyword(s):  
Filter Press ◽  
Carbonate Reservoirs ◽  
Additional Stress ◽  
Far Field ◽  
Fracture Geometry ◽  
Hydrocarbon Production ◽  
Upward Growth ◽  
Degradation Behaviors ◽  
Experimental Findings ◽  
Effective Seal

Abstract The technique of employing specialized particulates for far-field diversion is well-established during hydraulic fracturing treatments in unconventional formations and is being investigated for use in conventional formations. Far-field diverters (FFD) divert fluid away from the wellbore far into the formation. The injection of FFD at the beginning of the treatment provides an additional stress barrier between the producing interval and adjacent layers by depositing at the layer boundaries where higher leak-off is encountered. The ensuing restriction in height growth maximizes fracture extension within the producing zone, optimizing geometry for increased hydrocarbon production while limiting excess water. Polylactic Acid (PLA) polymer is self-degradable, compatible with reservoir fluids, and has a variety of compositions for different temperature applications. Blending proppant with PLA has been seen to significantly improve the strength of the deposited far-field diverter. Therefore, PLA powder and silica proppant are blended to develop Generation-1 far-field diverter (FFD-Gen1). However, many silica proppants have greater density than PLA, leading to separation during transport which prevents these two components from depositing evenly at the upper fracture boundary. This results in a situation in which excessive downward growth is prevented while upward growth is left unchecked. For this reason, both components need to be simultaneously deposited in order to develop an effective seal. Generation-2 far-field diverter (FFD-Gen2) is developed by replacing silica proppant of FFD-Gen1 with a deformable proppant having a density nearly equal to the polymer, which enables uniform deposition on all adjacent formation boundaries where leakoff is encountered. The deformable characteristic improves the pressure withstanding capacity of the diverter pack. The deposition and degradation behaviors are investigated in the laboratory by performing HTHP filter press and plug stability experiments. Experimental findings suggest that the primary selection criteria for acceptable performance are the material's mechanical properties. This methodology is used to select the appropriate FFD materials to optimize fracture geometry in carbonate reservoirs. Successful applications prevent excessive water production and substantially increase hydrocarbon production as illustrated in a three well case studies.

Modeling Acid Fracturing Treatments with Multi-Stage Alternating Injection of Pad and Acid Fluids

2021 ◽  
Author(s):  
Rencheng Dong ◽  
Mary F. Wheeler ◽  
Hang Su ◽  
Kang Ma
Keyword(s):  
Viscous Fingering ◽  
High Viscosity ◽  
Carbonate Reservoirs ◽  
Acid Etching ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Acid Fracturing ◽  
Fracture Surfaces ◽  
Low Viscosity ◽  
Multi Stage

Abstract Acid fracturing technique is widely applied to stimulate the productivity of carbonate reservoirs. The acid-fracture conductivity is created by non-uniform acid etching on fracture surfaces. Heterogeneous mineral distribution of carbonate reservoirs can lead to non-uniform acid etching during acid fracturing treatments. In addition, the non-uniform acid etching can be enhanced by the viscous fingering mechanism. For low-perm carbonate reservoirs, by multi-stage alternating injection of a low-viscosity acid and a high-viscosity polymer pad fluid during acid fracturing, the acid tends to form viscous fingers and etch fracture surfaces non-uniformly. To accurately predict the acid-fracture conductivity, this paper developed a 3D acid fracturing model to compute the rough acid fracture geometry induced by multi-stage alternating injection of pad and acid fluids. Based on the developed numerical simulator, we investigated the effects of viscous fingering, perforation design and stage period on the acid etching process. Compared with single-stage acid injection, multi-stage alternating injection of pad and acid fluids leads to narrower and longer acid-etched channels.

Effective Flow Properties for Cells Containing Fractures of Arbitrary Geometry

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0965-0980 ◽  
Author(s):  
A.. Sakhaee-Pour ◽  
Mary F. Wheeler
Keyword(s):  
Transport Properties ◽  
Cell Model ◽  
Petroleum Industry ◽  
Spatial Location ◽  
Effective Porosity ◽  
Single Fracture ◽  
Fracture Geometry ◽  
Hydrocarbon Production ◽  
Flow Models ◽  
Matrix Permeability

Summary Hydrocarbon production from unconventional resources such as shale usually entails stimulation by hydraulic fracturing, which results in nonplanar (curved) fractures. However, most reservoir models assume that the induced fractures are planar for the sake of simplicity. Considering the growing interest of the petroleum industry in better understanding production from these resources, we develop a fracture-cell model to capture the effects of fracture nonplanarity on transport properties. To build a realistic reservoir model for a fractured formation, we must account for three types of interactions: matrix-matrix (M-M), matrix-fracture (M-F), and fracture-fracture (F-F). The transport properties of the M-M interaction are based on laboratory measurements. In this study, we analytically determine the transport properties of the two other types of interactions (M-F and F-F). For this purpose, we account for the aperture size and spatial location of the fracture. As a result, we provide effective porosity and effective anisotropic permeabilities for a reservoir cell that contains a fracture inside it. The reservoir cell with transport properties that are modified is a fracture cell. We implement the fracture-cell model in a reservoir simulator and perform analyses for a single fracture and for multiple intersecting fractures; these fractures are nonplanar. The analyses include both single- and multiphase flow models and show that the hydrocarbon pressure inside the reservoir is strongly dependent on the fracture geometry when the matrix permeability is smaller than 1 µd. Thus, it is crucial to model the fracture geometry more accurately in unconventional reservoirs with ultralow permeabilities such as shale. One can easily implement the developed fracture-cell model in reservoir simulators, and there is no local refinement around the fracture. The main advantage of the proposed model is its simplicity, conjoined with its ability to capture the nonplanarity of the fracture. The developed model has major applications for understanding production from formations that are heavily fractured.

Numerical simulation and analysis of the influence of fracture geometry on wormhole propagation in carbonate reservoirs

2019 ◽  
Vol 198 ◽  
pp. 124-143 ◽  
Author(s):  
Ning Qi ◽  
Guobin Chen ◽  
Chong Liang ◽  
Tiankui Guo ◽  
Guoliang Liu ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Carbonate Reservoirs ◽  
Fracture Geometry

Integrated processing and interpretation to image and derisk a carbonate reservoir clouded by shallow gas — A case study from offshore Vietnam

2021 ◽  
Vol 40 (5) ◽  
pp. 357-364
Author(s):  
Jaewoo Park ◽  
Craig Hyslop ◽  
Da Zhou ◽  
Arjun Srinivasan ◽  
Patricia Montoya ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Model Building ◽  
Integrated Approach ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Shallow Gas ◽  
Hydrocarbon Production ◽  
Field Development ◽  
Processing Depth ◽  
Seismic Image

Carbonate reservoirs are increasingly becoming an important resource for hydrocarbon production because they contain the majority of remaining proven oil and gas reserves. In this context, carbonate reservoirs could represent new opportunities; however, there is still a lack of understanding of their subsurface status and characterization. Carbonate reservoirs are more difficult to evaluate than their siliciclastic counterparts because many aspects of carbonate rocks make their seismic image signature complex and difficult to interpret. Moreover, the presence of complex overburden such as shallow gas accumulation can exacerbate amplitude and phase fidelity at the reservoir, which introduces an additional imaging challenge. This makes field development of carbonate reservoirs extremely difficult because field development requires detailed delineation of characteristic karst features to avoid drilling hazards and sudden water breakthrough. In this paper, we demonstrate that a tight integration of signal processing, depth model building, and imaging, as well as near-real-time seismic interpretation feedback, is the key to success for imaging complex carbonate reservoirs with overburden challenges. Our findings show that such an integrated approach can result in a substantially better image, reduced depth uncertainty, and better delineation of karst and fractures. It can also aid in well placement and improve reservoir property modeling.

Multiple In-Situ Stress Measurements in Carbonate Reservoirs for CO2 Injection Capability Assessment and Far-Field Strain Calibrations

2022 ◽  
Author(s):  
Javier Alejandro Franquet ◽  
Viraj Nitin Telang ◽  
Hayat Abdi Ibrahim Jibar ◽  
Karem Alejandra Khan
Keyword(s):  
Oil Recovery ◽  
Fracture Initiation ◽  
In Situ Stress ◽  
Carbonate Reservoirs ◽  
Lateral Strain ◽  
Co2 Injection ◽  
Far Field ◽  
Pressure Derivative ◽  
Fracture Closure

Abstract The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done. The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.

Pillar Fracturing Production Enhancement Results for Mature, Clay Sensitive Reservoir in Ecuador

2021 ◽  
Author(s):  
Alvaro Javier Izurieta ◽  
Juan Carlos Guaman ◽  
Andrea Morillo ◽  
Guillermo Pabon ◽  
Magaly Abril
Keyword(s):  
Surface Modification ◽  
Laboratory Tests ◽  
Planning Process ◽  
Fracture Initiation ◽  
Candidate Selection ◽  
High Permeability ◽  
Pillar Stability ◽  
Fracture Geometry ◽  
Hydrocarbon Production ◽  
Planning Stage

Abstract This paper discusses pillar fracturing technique application along with customized fluids formulation in a mature oilfield (low reservoir pressure and high permeability) where complex mineralogy limited the use of traditional stimulation practices. Integrated reservoir analysis, laboratory tests (fracturing gel, chemical consolidation resin) and hydraulic fracture modeling performed to obtain a major productivity increase (up to 16x increase) by a combination of tip screen out (TSO) and pillar fracturing techniques. The combination of clay sensitivity, low pressure and high permeability requires a careful planning stage for pillar fracturing (PF) application. The first step is to evaluate PF feasibility by a candidate selection factor using geomechanical parameters such as closure stress, net pressure, etc. The next step is to customize the fracturing gel to sustain high shear stress during TSO and guarantee a complete gel break. Pillar stability is supported by confined stress developed by the surface modification agents mixed on the fly with proppant. This stage requires laboratory tests based on resin hardener ratio at reservoir temperature and time. Clays such as kaolinite, chlorite, etc., limits the applicability of traditional acid stimulation blends on this reservoir. Completion brine as well as fracturing gel requires the addition of a quaternary amine to temporally avoid fines migration during workover operations before and after fracturing. Without this customization, conventional or even pillar fracturing will perform below expectations. Not all reservoirs are candidates for pillar fracturing, candidate selection is a critical step in the planning process. Two types of candidates are documented on this paper, new fracturing as well as re-fracturing jobs. For both cases a numerical gridded fracture simulator is used to understand fracture geometry, diagnose and match previous treatments. Pillar fracturing is designed and executed using pulsed or cycled proppant fracture stimulation, providing infinite acting conductivity for enhanced hydrocarbon production. It significantly reduces screen out tendency leading to higher proppant concentration, as well as total proppant mass reduction when compared to conventional TSO fracture design. The use of surface modification agents (SMA) improves pillar stability and reduces proppant flow back risk if adequate compressive strength is developed during curing time after fracturing operations. Production results show up to 16 times increase, exceeding expected production by conventional fracturing. A complete workflow to characterize, design and simulate a pillar fracturing job using proprietary geomechanical candidate selection criteria is presented. The combination of TSO and pillar fracturing yields a significant production increase over conventional fracturing and acid stimulation. The use of gridded 3D simulator significantly improves the understanding of previous fracturing jobs helping to propose improvements on fracture initiation depth, polymeric load and pumping schedule for re-fracturing candidates.

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