In order to improve HSE performance many companies have implemented voluntary (i.e. non-regulation driven) programs designed to engage supervisors and employees and reduce injuries and incidents. Over the years these programs have had significant effect in improving performance and making the workplace safer. While done with the best intentions, most programs introduce an element of administrative burden on the organization and sites. The cumulative impact on a supervisor's daily activities can be substantial and result in excessive time spent in front of a computer, rather than with their teams. This means less opportunity to provide leadership on safety and consequently, undermine efforts to improve.
In 2017, based on a combination of employee surveys and safety stand downs Dyno Nobel North America (‘DNA’ or the company), a global explosives manufacturer and service provider, identified the need to evaluate the burden on the organization of safety programs to rationalize and improve them as appropriate. One of the main concerns of this effort was how to remove or modify these programs to be less of a burden, yet not increase the risk. It can be related to the game Jenga®, where players remove blocks from a stack without destabilizing the structure.
DNA engaged a consultant, The Jonah Group, to build a risk model based on the principles of process safety management interwoven with the understanding of human factors and performance. Once the model was built, it was piloted at three of the company's field sites to ensure efficacy and adjust as necessary. Afterwards, the model was used at nine field locations. The evaluation included a review of equipment, process and procedure, and centered around interviews with supervisors and front-line employees. Surveys were conducted with supervisors to complete the view of where they spend their time.
Results and recommendations were summarized in a report. One of the key findings was that while there were opportunities to improve certain elements of the voluntary safety programs, there were more significant opportunities with regards to management of change, process safety and risk awareness, site safety leadership, communication, and process efficiency. The recommendations will help the company improve organizational effectiveness and free up supervisors to better oversee, and lead, site safety.
This course provides a fundamental understanding of process safety techniques and how applying these techniques can improve safety, equipment reliability, environmental performance and reduce overall costs. It presents an overview of the elements comprising process safety, practical examples and how process safety can be integrated into day-to-day operations. Working and studying abroad is a huge part of the oil and gas industry and despite the impact on a professional’s career and personal life, little guidance is available for those considering the big move. At this event, we will be sharing stories from those who have gone through the same process and explore some of the benefits and difficulties of diverse working environments. Sustainability means many different things to different people. For governments, it means ensuring development that meets the needs and aspirations of the present without compromising the ability of future generations to meet their own needs.
When analyzing gas production from Green River Basin vertical wells in western Wyoming, geomechanical log curves have proven to be superior at predicting production performance than gamma ray alone. Production logs showed many “clean” sandstones that were thought to be of high quality by their gamma ray response were underperforming. Conversely, higher gamma ray sections of the reservoir were contributing or outperforming expectations. The discrepancy is associated with the basin's fluvial geologic environment. An alternative method was, therefore, required to grade reservoir quality independent of gamma ray response.
Acquiring advanced logs on every well to determine porosity and reservoir quality is time intensive and uneconomical in many mature dry gas fields. A new technique was developed using geomechanical properties derived from drill bit vibrations to create a supervised mechanical facies model specific to the Lower Lance Pool (LLP).
Continuous, high-resolution measurements of drilling-induced vibrations were obtained in several dozen vertical wells in the region. Data collected were used to provide stiffness coefficients and determine geomechanical properties including Young's modulus and Poisson's ratio.
The geomechanical curves were compared to offset data to create a supervised mechanical facies model related to porosity, permeability and Vclay. The calibrated model was applied to all legacy vertical wells with drill bit vibration data and LLP completions. The model was applied to several new vertical wells to assist in the completion strategy. Production was logged to validate the mechanical facies model's ability to predict production.
The mechanical facies defined several potential horizontal landing zones in a pilot well drilled through the LLP. The model was then applied to the lateral section and used to stage the well by grouping similar facies together within a stage, thus minimizing heterogeneity and optimizing perforation efficiency.
Production logs showed the mechanical facies identified producible and non-producible reservoir independent of gamma ray measurement. Vertical wells where geomechanical data were used to target mechanically favorable rock outproduced offset wells by ~20% in the LLP. The mechanical facies model determined the landing zone for the operator's first horizontal well in the LLP. The model was also applied to the lateral section to more intelligently implement a geomechanically informed completions strategy.
Differentiating high- and low-delivery reservoir without the deployment of advanced logging suites is operationally and economically more efficient. A supervised mechanical facies model can be calibrated with supporting data and then applied to future wells by solely recording and analyzing drill bit vibration data. Wells can be completed in a geomechanically-informed fashion leading to better production and more economic completions.
Process zone stress (PZS) has been found to correlate to poor stimulation efficiency and low production. Several models for estimating PZS have been developed by correlating to petrophysical logs (e.g., bulk density (RhoB), porosity (PhiE) and shale volume (Vsh)). Common practice, which does not capture lateral reservoir heterogeneity, uses logs in vertical wells to build a layer-cake model. This study uses geomechanical data acquired while drilling a horizontal well to build a calibrated petrophysical interpretation of bulk density, porosity and shale volume in order to estimate PZS. This workflow results in a stage-by-stage prediction of possible operational issues, which can improve operational efficiency and maximize the effectively-stimulated lateral length.
Geomechanical data were acquired in both a pilot and horizontal well in the Lower Lance Pool (LLP), Green River Basin, Wyoming. The geomechanical properties (Young's Modulus, Poisson's Ratio and VTI anisotropy) were calibrated with wireline in the pilot to calculate RhoB, PhiE, and Vsh. The calibrated petrophysical model was then applied to the mechanical data in the lateral wellbore, providing the inputs necessary for the PZS calculation.
Three PZS models were built in a 3D multi-well finite difference simulator using each of the three petrophysical inputs. Scalars for the models were calibrated to offset DFIT data. The resulting models were compared to determine the optimal model. Pre-stimulation instantaneous shut in pressures (ISIP) was evaluated in the horizontal well for each stage. High pre-job ISIP values are an indicator of stages that may be difficult to break down because of the apparent increase in stress associated with initiating and propagating the fracture. The ISIP analyses were compared to the prediction based on the synthetic PZS models to validate the result.
The three PZS models were evaluated for consistent, predictive behavior in the LLP. Results indicate that the RhoB and PhiE models were more consistent than the Vsh model. Additionally, the RhoB model benefits from more widely available calibration to offset triple-combo data, allowing it to be used with greater confidence throughout the basin.
A predicted ISIP was calculated (closure pressure + PZS) and compared to the pre-job ISIP analyses. The model predicted an average ISIP around 2% or less across the lateral. In contrast, a layer-cake model using the pilot data workflow predicted ISIP around 9% of actual. This variability may be caused by lateral changes in reservoir quality which the layer-cake model does not account for.
This workflow provides a calibrated method for incorporating PZS into a horizontal well using geomechanical data. The application accounts for the reservoir's heterogeneity, where the layer-cake approach to applying PZS is insufficient. The integration of the petro-mechanical and completion methodologies provides a unique opportunity to optimize completions in horizontal wells.
Study made from the results observed over a particular application objective with one of the recently developed proppant fracturing techniques known as Channel Fracturing. This technique was used in this application to place a proppant fracturing treatment in a tight gas reservoir which pushes the installed well completion to reach its mechanical limit capabilities. Channel (or pillar) fracturing was applied in multiple cases with the intention to constrain the pressure increase commonly observed during a fracture job execution.
Zhu, Haiyan (Chengdu University of Technology) | Zhao, Ya-Pu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Feng, Yongcun (Institute of Mechanics, Chinese Academy of Sciences) | Wang, Haowei (Institute of Mechanics, Chinese Academy of Sciences) | Zhang, Liaoyuan (University of Chinese Academy of Sciences) | McLennan, John D. (University of Texas at Austin)
Haiyan Zhu, Chengdu University of Technology, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, and Institute of Mechanics, Chinese Academy of Sciences; Ya-Pu Zhao, Institute of Mechanics, Chinese Academy of Sciences and University of Chinese Academy of Sciences; Yongcun Feng, University of Texas at Austin; Haowei Wang, Southwest Petroleum University; Liaoyuan Zhang, Sinopec Shengli Oilfield Company; and John D. McLennan, University of Utah Summary Channel fracturing acknowledges that there will be local concentrations of proppant that generate high-conductivity channel networks within a hydraulic fracture. These concentrations of proppant form pillars that maintain aperture. The mechanical properties of these proppant pillars and the reservoir rock are important factors affecting conductivity. In this paper, the nonlinear stress/strain relationship of proppant pillars is first determined using experimental results. A predictive model for fracture width and conductivity is developed when unpropped, highly conductive channels are generated during the stimulation. This model considers the combined effects of pillar and fracture-surface deformation, as well as proppant embedment. The influence of the geomechanical parameters related to the formation and the operational parameters of the stimulation are analyzed using the proposed model. The results of this work indicate the following: 1. Proppant pillars clearly exhibit compaction in response to applied closure stress, and the resulting axial and radial deformation should not be ignored in the prediction of fracture conductivity. Introduction In conventional hydraulic-fracturing treatments, it is presumed that proppant is distributed uniformly in the fracturing fluid and generates a uniform proppant pack in the fracture (left-hand side of Figure 1). The propped fracture serves as a high-conductivity channel facilitating fluid flow from the reservoir to the well. Channel fracturing is a new fracturing concept, and replaces a nominally homogeneous proppant pack in the fracture with a heterogeneous structure containing a network of open channels (Figure 1, right) (Gillard et al. 2010). This channel-like structure is achieved by using fiber-laden fluids or self-aggregating proppant together with a pulsed-pumping strategy. In channel fracturing, the interaction between the proppant and fracture surfaces is a "point" contact, in contrast to the "surface" contact assumed to exist in conventional fracturing.
The Magallanes Basin of Southern Chile is the southern-most hydrocarbon-producing basin in the world. The main source of the gas production in this basin is from the Glauconite Formation. The Glauconite is a clay and feldspar rich formation with extremely low permeability requiring hydraulic fracturing to recover the hydrocarbons and enhance well performance. In this project, fracture simulations with a fully three-dimensional finite element model were integrated with statistical analysis and used in an optimization study of hydraulic fracturing in the Glauconite Formation.
The mechanical earth model was used to estimate the in-situ stress contrast, Young's Modulus, and leak-off profile with depth. Tri-axial compression tests of core were used to validate static Young's Modulus estimates while mini-frac data and fracture stimulation data were history matched and used to validate and/or modify in-situ stress and leak-off profiles with depth. The history matched treatments were then used to populate the database with the resulting hydraulic and propped fracture dimensions. Ultimately, a database that includes in-situ stress, stress contrast, Young's Modulus, leak-off, propped and un-propped fracture dimensions (length and conductivity) was developed.
Finally, both the database and multi-variate statistical analysis were used to show the role of mechanical earth modeling in enhancing and improving the understanding of fracture optimization in the Glauconite Formation. Results from hybrid fracture fluid treatments were compared to treated water fracture treatments to determine the optimum fracture stimulation design for this unconventional extremely tight gas resource.
This work provides a benefit to the petroleum industry by: Using a geo-mechanical finite element model to improve the understanding of the propped fracture dimensions achieved by hybrid and treated water fracture treatments in an unconventional resource like the Glauconite Formation. Establish the key drivers for successful water-frac treatments.
Using a geo-mechanical finite element model to improve the understanding of the propped fracture dimensions achieved by hybrid and treated water fracture treatments in an unconventional resource like the Glauconite Formation.
Establish the key drivers for successful water-frac treatments.
Advances in fracture mapping and full 3D modeling have yielded new insights into hydraulic fracture geometry, but it is still impossible to predict height growth. Fracture mapping data collected from a large number of treatments in different basins yield a rule-of-thumb for expected fracture height over fracture length (aspect ratio), but in specific cases fracture design optimization requires a more accurate forecast for height growth. Calibrated models with full 3D fracture geometry will give the best results, but in many projects the available data to calibrate such a model is severely limited. Knowing this, the question this paper attempts to answer is: "Will using a full 3D model give more reliable predictions of fracture geometry (maybe height growth) compared with pseudo-3D models?".
Using data from an instrumented field test and routine fracture treatments, the results of the different fracture models are tested. Even when detailed knowledge of stress and geomechanical properties are available, it is impossible to match observed fracture geometry using only conventional hydraulic fracture physics. So, even a full 3D model does not provide a true prediction of fracture geometry. Both pseudo3D and full 3D fracture models can match observed fracture geometry, but only by introducing additional parameters beyond conventional fracture propagation physics, such as formation lamination or fracture tip pore pressure.
A full 3D model with default input parameters and conventional fracture physics yields a prediction of strong containment, even for modest stress difference between pay and overburden. This agrees in general with average observed geometry, but in specific cases, fracture height growth still occurs, showing that in these cases the model was inadequate and needs to be calibrated. Pseudo-3D models tend to overestimate height growth for default inputs, but that can also be modified to match the stronger containment often seen in practice. Therefore, no benefit is obtained from fully gridded simulation models in routine cases where critical inputs and calibration data are unavailable.