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Collaborating Authors
Kuroda, Shintaro
Abstract The objective of this paper is to quantify both the formation stress depletion and the pore pressure depletion caused by production from existing parent wells in the Eagle Ford using observed field data. When future infill wells are added to the development area, the formation pore pressure may be depleted to a certain extent due to production from the existing parent wells. This pore pressure depletion may also result in formation stress depletion as well. These depletion effects may influence fracture propagation during the hydraulic fracturing operation, and potentially result in asymmetric fracture propagation and significant frac hits to the parent wells. The biggest concern, however, is that well productivity in the depleted area would be lower than that expected under initial reservoir conditions. Therefore, it is important to understand how far these depletion effects have propagated in the area. This paper introduces a field case study integrating field test data such as a PBU (Pressure Build-up) survey in the parent well, aligned DFITs (Diagnostic Fracture Injection Tests) in the child wells, and flowback data after hydraulic fracturing in both the parent and child wells. The PBU survey in the parent well provides the current pore pressure. Aligned DFITs results in the multiple child wells indicates how the current formation stress changes in relation to distance from the parent well. Flowback data can be used to evaluate the pore pressure at a particular well location at a certain point in time as introduced by Jones (2014). By integrating both the field observed data and the evaluation results and then running the fracture propagation simulation, it is possible to evaluate how these depletion effects affect propagation behavior. The evaluated pore pressure and stress gradually changes from the parent well location to the child well locations as a function of well spacing. PBU survey results were used as an anchoring point of pressure depletion at the parent well location. A child well closest to the parent well was observed to have much lower pore pressure and stress than child wells that were farther away. Based on these observations, depleted pore pressure and stress distribution functions were created in relation to distance from the parent well. Fracture propagation simulations were then performed considering the observed depleted stress and pressure distributions. The fractures in the simulated models tended to propagate in the direction of the parent well rather than the new child wells because of the lower stress and pressure. These results were consistent with frac hit field observations. This paper presents not only how the pore pressure depletion spreads but also how the stress depletion spreads around the parent well in shale reservoirs based on observed field data. This field case study can provide technical support to shale operators regarding well spacing, fracture design optimization and reserves evaluation. Additionally, this study can be applied to climate change measures because CCS (Carbon Capture and Storage) or CCUS (Carbon Capture, Storage and Utilization) projects often target the depleted reservoirs and need to consider the formation stress condition after depletion for CO2 injection.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
Abstract The objective of this paper is to investigate how to acquire fracture closure pressure data accurately and cost-effectively in shale development activities. If the injection volume is small during a hydraulic fracturing job, it is a common practice to consider the ISIP (Instantaneous Shut-In Pressure) as a proxy of fracture closure pressure, which generally requires a long falloff period to evaluate. However, ISIP should consist of variable parameters such as the original closure pressure, net pressure, stress shadow effect, and mid-field fracture complexity. In this paper, we introduce the consecutive DFITs (Diagnostic Fracture Injection Test) approach. Closure pressure is evaluated by falloff pressure analysis after a micro fracturing injection operation, and pore pressure could also be evaluated if the falloff period is long enough. This micro fracturing operation is generally called DFIT. In order to evaluate how the ISIP, closure pressure, and pore pressure change from stage to stage, we performed DFITs consecutively at the sequential hydraulic fracturing stages in a horizontal well drilled in the Eagle Ford shale. The consecutive DFITs revealed that the ISIP gradually increased up to certain level from fracturing stage to stage as expected. However, the observed closure pressure was almost constant in the sequential stages, which was against our expectations. In addition, the evaluated pore pressure was also almost constant. Initially we expected that closure pressure would increase because of the uplift due to the stress shadow effect. Since the consecutive DFITs showed the same closure pressure in each stage, we concluded that stress uplift could disappear before the fracture closure in next stage or that the stress shadow had little impact on the closure pressure and the pore pressure in next stage under the current fracture design. On the other hand, the ISIP could be affected by the stress shadow in the short term or by the mid-field fracture complexity becoming higher than the previous stage. The correlation between the ISIP and the closure pressure was established with these consecutive DFITs results. Although the gap between the ISIP and closure pressure varies from stage to stage, it was confirmed that the correlation, with some uncertainties, could be used to estimate the closure pressure within an acceptable range. This paper presents the Eagle Ford case study, which confirmed how accurately ISIP can determine closure pressure considering multiple factors. There are hydraulic fracturing operations in huge number of horizontal wells in the shale development. Therefore, the correlation built by consecutive DFITs is useful because that correlation can provide operators with the confidence to optimize the completion design based on the ISIP which can be obtained at a low cost.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.66)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
ABSTRACT: This paper summarizes our experience using two hydraulic fracture simulators that include DFN models of natural fractures that have been well characterized. For a well pad within the Horn River basin, a 3D DFN model was built using scaled core and image log characterization of the natural fractures. Fracture properties and hydraulic fracturing parameters were adjusted to provide a match to the microseismic event distributions observed in the field. This simulator induces a hydraulic fracture at each entry point and then balances the growth of that fracture and the invasion of natural fractures by considering the hydraulic, orientation and connection properties of the natural fractures. A second simulation of hydraulic fracturing was performed in a propagation simulator that uses a 2D DFN model that is extended vertically across all the reservoir zones. This simulator uses natural fractures strictly as mechanical weaknesses in the rock. The effect of natural fractures on the propagating fractures is determined by a crossing rule. Stress shadowing both between fracturing stages and wells was also utilized to both increase complexity and to modify height growth. The 3D DFN fracture hydraulic model produced highly complex stimulated fracture networks whereas the 2D DFN based propagation model produced a less complex stimulation. Both models developed inter-zonal connections that could explain the hydraulic fracturing pressure hits and production interference observed between wells in the field. A key factor impacting stimulated reservoir width in both models is the variation in primary natural fracture orientations.
- North America > Canada > British Columbia (0.34)
- North America > United States > California (0.29)
Hydraulic Fracture Design in the Presence of Highly-Stressed Layers: A Case Study of Stress Interference in a Multi-Horizontal Well Pad
Ueda, Kenji (INPEX Corporation) | Kuroda, Shintaro (INPEX Corporation) | Rodriguez-Herrera, Adrian (Schlumberger) | Garcia-Teijeiro, Xavier (Schlumberger) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio J. (Nexen Energy ULC) | Tokunaga, Hiroyuki (INPEX Corporation) | Makimura, Dai (Schlumberger) | Lehmann, Jurgen (Nexen Energy ULC) | Petr, Christopher (Nexen Energy ULC) | Tsusaka, Kimikazu (INPEX Corporation) | Shimamoto, Tatsuo (INPEX Corporation)
Abstract A design of hydraulic fracturing in variably-stressed zones is one of key components for an effective multi-zone, multi-horizontal well pad treatment. In the recent literature, optimum completion strategies catering for stimulation-induced in-situ stress changes are discussed, however, only few of these focus on vertical stress changes and its impact on multi-zone fracture geometries. In this paper, we present an approach to design contained hydraulic fractures in a high stress layers by studying the role of vertical stress shadowing on actual field data. In modeling hydraulic fractures with pseudo-3D models, if fracture simulations are initiated in high stress zones, "artificially" unbounded height growth results in very limited lateral propagation. On the other hand, 3D hydraulic fracturing models are too computationally expensive to optimize large design jobs, for example, in multi-horizontal well pads. In this paper, we employ a Stacked Height Growth Model, whereby fractures are also discretized vertically yet retain the numerical formulation pseudo-3D models. Coupling with finite element stress solvers then allows to identify vertical stress changes in the vicinity of induced hydraulic fractures and to understand the interference between hydraulic fracture sequences and their respective microseismic signatures. Considering a potential combination of fracturing sequences, it was revealed that stress perturbations from the neighboring well hydraulic fractures initiating from low stress layers can be used to increase stress within the same zone and also potentially reduce stresses in higher-stress layers above and below. By modeling and calibrating an actual multi-zone, multi-horizontal stimulation job, we elaborate on the benefits of increasing stress barriers before fracturing in higher-stress layer to avoid the chances of re-fracturing from high stress zones. Regarding hydraulic fracture geometries, we explain our results by analyzing actual microseismic observations with respect to simulated stress patterns after stimulation. We explore the notion of deliberately ordering hydraulic fracture to manage vertical interference and create more contained fractures in a multi-zone horizontal well pad. Fracturing in a higher-stress zone will naturally divert the energy into low stress, potentially unproductive zones. In an effort to manage this phenomenon, this paper presents one of the few data-rich case studies on multi-zone, multi-well engineered stimulation design. The approach shown in this paper can be a helpful reference to understand fracture height growth in the presence of both vertical and horizontal stress shadowing.
- North America > United States > Texas (1.00)
- North America > Canada > British Columbia (0.68)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- (12 more...)
Abstract Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network growth, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be clearly understood to optimize stimulation design and completion strategy. Unfortunately, the existing single planar fracture models used in the industry today are not able to simulate complex fracture networks. A recently developed unconventional complex fracture propagation model is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate simultaneously and intersect/cross each other. This paper presents an integrated operator, non-operator and service provider's approach to optimize future hydraulic fracture design by fully integrating all the data captured in the Canadian Horn River shale. Based upon insight from the study, which was initiated by the non-operator, continued by the operator and supported by the service provider in two different countries, the operator and non-operator needed to make more informed design decisions and understand the interaction between the shale, the hydraulic and pre-existing natural fracture network and reduce costs. Data were captured from reference vertical wells and a multi-well pad. The data incorporated into the study included geophysical, geological, petrophysical, geomechanical and engineering such as dfit (small volume of water pumped into target formation) derived fracture closure pressure, production and pressure data from the horizontal wells in the pad. A generation of 2D natural fracture network is also included in the paper by defining natural fracture parameters such as length, orientation, spacing, friction coefficient, cohesion, and toughness which are almost entirely validated using lab data and geomechanical interpretation. The complex hydraulic fracture simulation results calibrated with microseismic and fracturing treatment data were incorporated into a shale gas, numerical simulator and further calibrated with current production history of the candidate multi-wells. The results of the hydraulic fracture, natural fracture and reservoir models were utilized to understand the fracture propagation mechanism in the Canadian Horn River shale gas formation. As a result of the project, the team is now able to run different hydraulic fracture design scenarios and assess the impact that each key design parameter has over the candidate well's long term production using a numerical simulator with a unique gridding process. Based on these findings, the operator and non-operator now have an insightful tool that could be used as the building block for future optimization of the fracture design
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Horn River Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Otter Park Formation (0.94)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Muskwa Field > Muskwa Formation (0.94)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Evie Lake Field (0.89)
First Successful Hydraulic Fracturing in the Offshore Abu Dhabi: Part1—Flexible Design to Unlock a Tight Gas with Uncertainties—
Kuroda, Shintaro (INPEX) | Kaneko, Masayuki (JODCO) | Al Ameri, Fahed (ADNOC) | Al Zarouni, Asim (ADNOC) | Al Zaabi, Mohamed R. (ADNOC) | Al Awadi, Farhaad Khaled (ADMA-OPCO) | Sabri, Abdul Moez (ADMA-OPCO)
Abstract The hydraulic fracturing technology is widely applied in tight reservoirs, including shale reservoirs, as one of the established reservoir stimulation methodologies to enhance the productivity. Even though the hydraulic fracturing is currently a common technique, there are remaining challenges in offshore fields with the high degree of geological and geomechanical uncertainties. In offshore hydraulic fracturing operations, key issues are the limited deck space for the required equipment on-board and economical aspects of the surface equipment including stimulation vessels due to the limited number of dedicated offshore stimulation vessels in the world. In addition, the limited reservoir information brings uncertainties in the hydraulic fracture design and causes difficulties in finalizing the operation plans from the timing and logistics point of view. This paper contains the first part of the two successive parts of a case study will be shown on successful optimization and productivity enhancement of actual offshore hydraulic fracturing for a deep tight gas reservoir with considerably limited formation data and under a high-pressure and high-temperature (HP/HT) environment. This successful operation was recognized as a landmark in this region, in terms of the first hydraulic fracturing operation in the offshore Abu Dhabi. In this paper (part 1), we describe how the flexible hydraulic fracture design led to an efficient productivity enhancement. The hydraulic fracture design was optimized by the integrated data acquisition strategy and the successive flexible adjustment from the design stage at office to the actual main treatment at wellsite. The relevant fracture design components like proppant usage and size can be optimized, based on sensitivity studies assuming not only all possible geological and geomechanical circumstances but also the actual pre-frac well test and data-frac results. In part 2, the key factors will be highlighted on this successful hydraulic fracturing result against the difficulties from operational point of view (Al Ameri et al. 2014). The work flow and successful strategy in our hydraulic fracturing design and execution can be applied to other offshore tight-sand gas reservoirs including those under HP/HT condition. The optimized design of hydraulic fracturing provides an effective operation and enables more economical field development for the tight reservoirs.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.35)