Geomechanical Controls on Frac-Hits

The communication among the horizontal wells or "frac-hits" issue have been reported in several field observations. These observations show that the "infill" well fractures could have a tendency to propagate towards the "parent" well depending on reservoir in-situ conditions and operational parameters. Drilling the horizontal wells in a "staggered" layout with both horizontal and vertical offset could be a mitigation strategy to prevent the "frac-hits" issue. In this study, we present a detailed geomechanical modeling and analysis of the proposed solution. For numerical modeling, we used our state-of-the-art fully coupled poroelastic model "GeoFrac-3D" which is based on the boundary element method for the rock matrix deformation/fracture propagation and the finite element method for the fracture fluid flow. The "GeoFrac-3D" simulator fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The simulation results demonstrate that production from a "parent’ well causes a non-uniform reduction of the reservoir pore pressure around the production fractures, resulting in an anisotropic decrease of the reservoir total stresses, which could affect fracture propagation from the "infill" wells. We examine the optimal orientation and position of the "infill" well based on the numerical analysis to reduce the "frac-hits" issue in the horizontal well refracturing. The posibility of "frac-hits" can be reduced by optimizing the direction and locations of the "infill" wells, as well as re-pressurizing the "parent" well. The results suggest that arranging the horizontal wells in a "staggered" or "wine rack" arrangement decreases direct well interference and could increase the drainage volume.

Modeling of Before Closure Zero Slope Pressure Derivative in a Diagnostic Fracture Injection Test DFIT

Recent diagnostic fracture injection test (DFIT) data presented on a Bourdet log-log diagnostic plot showed derivative slope of 0 in the before closure (BC) portion of the DFIT response. Some works qualitatively describe it as radial flow. This behavior has not been quantitatively analyzed, modeled and matched. The present work disagrees with the hypothesis of radial flow and successfully matches the relatively flat trend in the Bourdet derivative with a model dominated by friction dissipation coupled with tip extension. The flat trend in Bourdet derivative occurs shortly after shut-in during the before closure period. Because a flat derivative trend suggests diffusive radial flow, our first approach was to consider the possibility that an open crack at a layer interface stopped the fracture propagation and caused the apparent radial flow behavior observed in falloff data. However, a model that coupled pressure falloff from diffusive flow into a layer interface crack with pressure falloff from closure of a fracture that propagated up to the layer interface failed to reproduce the observed response. Subsequently, we discovered that existing models could match the data without considering the layer interface crack. We found that data processing is very important to what is observed in derivative trends and can mislead the behavior diagnosis. We succeeded to match one field DFIT case showing an obvious early flat trend. The presence and dominance of geomechanics, coupled with diffusive flow, disqualify the description of the flat trend in Bourdet derivative as radial flow. Instead, flow friction coupled with tip extension can completely match the observed behavior. Based on our model, cases with a long flat trend have large magnitude near-wellbore tortuosity friction loss and relatively long tip extension distance. Further, we match the near wellbore tortuosity behavior with rate raised to a power lower than the usually assumed 0.5. The significance of these analyses relates to two key factors. First, large magnitude near wellbore tortuosity friction loss increases the pressure required for fracture propagation during pumping. Second, tip extension is a way to dissipate high pumping pressure when very low formation permeability impedes leakoff. Matching transient behavior subject to the presence of both of these factors requires lowering the near-wellbore tortuosity exponent.

No Need for Radio Active Tracer When Mother Nature Helps Detecting the Effective Hydraulic Fracture Height

The tight gas reservoirs of Haima Supergroup provide the majority of gas production in the Sultanate of Oman. The paper discusses a possibility of using the anomalies from natural radioactivity to evaluate the fracture height for complex tight gas in mature fields of Oman. The standard industry practice is adding radioactive isotopes to the proppant. Spectral Gamma Ray log is used to determine near wellbore traced proppant placement. Spectral Noise log in combination with Production logs helps to identify the active fractures contributing to production. These methods complement each other, but they are obviously associated with costs. Hence, majority of wells are fracced without tracers or any other fracture height diagnostics. However, in several brown fields, an alternative approach to identify fracture height has been developed which provides fit-for-purpose results. It is based on the analysis of naturally occurring radioactive minerals (NORM) precipitation. The anomalies were observed in the many gas reservoirs even in cases when tracers were not used. At certain conditions, these anomalies can be used to characterize fracture propagation and optimize future wells hydraulic Fracture design. A high number of PLTs and well test information were analyzed. Since tight formations normally don't produce without fracturing, radioactive anomalies flag the contributing intervals and hence fracture propagation. The main element of analysis procedure is related to that fact that if no tracers applied, the discrepancy between normalized Open Hole Gamma Ray and Gamma Ray taken during PLT after 6-12 months of production can be used instead to establish fracture height. This method cannot be applied for immediate interpretation of fracture propagation because time is required to precipitate NORM and using the anomalies concept. The advantage of this method is that it can be used in some fields to estimate the frac effectiveness of wells without artificial tracers. It is normally assumed that the Natural radioactivity anomalies appear mainly due to co-production of the formation water. However, in the fields of interest the anomalies appear in wells producing only gas and condensate. This observation provides an opportunity for active fracture height determination at minimum cost.

Hydraulic Fracturing Design Optimization Guidelines for Heterogeneous Reservoir

This paper describes the journey of hydraulic fracturing design solutions and implementation in Khazzan field. More than 100 wells have been stimulated with hydraulic fracturing in the field in the last decade. Most of these wells were treated with a single-stage massive propped hydraulic fracturing treatment aimed at stimulating the entire vertical productive zone in a single treatment. More recently, hydraulic fracturing has begun on the southern acreage from Khazzan, referred to as Ghazeer. Producing layers in this area are thicker and higher permeability and, as a result, more prolific. Based on the available data and experiences, the establishment of clear guidelines has become a requirement to help the understanding and adjust the hydraulic fracturing design for each well to be become a well-specific optimum design. During the stimulation journey, surveillance techniques have been utilized and implemented in the Khazzan and Ghazeer fields to provide and develop better understanding of the fracture propagation process. These data have proven essential to support stimulation design evolvement and determine if multiple fracturing stages are justified or whether a single stage would be sufficient. Based on a wide range of hydraulic fracture stimulation operations performed across the Khazzan and Ghazeer fields, a flowchart was developed to integrate all the lessons learned from the previous experience and help optimize future fracture design. Clear guidelines include the rationale between the selection of single or multiple fracturing stages, the selection of optimal pad fractions, and other associated details of the fracture design. This flowchart has been extensively validated with surveillance and has proven its inherent value in many stimulated wells, with either single or multiple proppant fracturing stages.

Characterize Fracture Development Through Strain Rate Measurements by Distributed Acoustic Sensor DAS

In multistage hydraulic fracturing treatments, the combination of extreme large-scale pumping (high rate and volume) and the high heterogeneity of the formation (because of large contact area) normally results in complex fracture growth that cannot be simply modeled with conventional fracture models. Lack of understanding of the fracturing mechanism makes it difficult to design and optimize hydraulic fracturing treatments. Many monitoring, testing and diagnosis technologies have been applied in the field to describe hydraulic fracture development. Strain rate measured by distributed acoustic sensor (DAS) is one of the tools for fracture monitoring in complex completion scenarios. DAS measures far-field strain rate that can be of assistance for fracture characterization, cross-well fracture interference identification, and well stimulation efficiency evaluation. Many field applications have shown DAS responses on observation wells or surrounding producers when a well in the vicinity is fractured. Modeling and interpreting DAS strain rate responses can help quantitatively map fracture propagation. In this work, a methodology is developed to generate the simulated strain-rate responds to assumed fracture systems. The physical domain contains a treated well that the generate strain variation in the domain because of fracturing, and an observation well that has fiber-optic sensor installed along it to measure the strain rate responses to the fracture propagation. Instead of using a complex fracture model to forward simulate fracture propagation, this work starts from a simple 2D fracture propagation model to provide hypothetical fracture geometries in a relatively reasonable and acceptable range for both single fracture case and multiple fracture case. Displacement discontinuity method (DDM) is formulated to simulate rock deformation and strain rate responds on fiber-optic sensors. At each time step, fracture propagation is first allowed, then stress, displacement and strain field are estimated as the fracture approaches to the observation well. Afterward, the strain rate is calculated as fracture growth to generate patterns as fracture approaching. Extended simulation is conducted to monitor fracture propagation and strain rate responses. The patterns of strain rate responses can be used to recognize fracture development. Examples of strain rate responses for different fracturing conditions are presented in this paper. The relationship of injection rate distribution and strain rate responses is investigated to show the potential of using DAS measurements to diagnose multistage hydraulic fracturing treatments.